Electrical power system modeling, design, analysis, and reporting via a client-server application framework

ABSTRACT

A system for intelligent web-based monitoring and management of an electrical system is provided. The system is configured to acquire real-time data output from the electrical system, and to transmit a user interface to a client terminal which is configured to display the user interface. In an embodiment, the system is configured to store a virtual system model of the electrical system. The system is configured to generate a predicted data output for the electrical system utilizing the virtual system model of the electrical system, monitor the real-time data output and the predicted data output of the electrical system, and initiate a calibration and synchronization operation to update the virtual system model when a difference between the real-time data output and the predicted data output exceeds a threshold.

RELATED APPLICATIONS INFORMATION

This application claims the benefit under 35 U.S.C. §119(e) of U.S.Provisional Application Ser. No. 60/979,347 filed Oct. 11, 2007. Thisapplication also claims priority as a Continuation-In-Part under 35U.S.C. §120 to U.S. patent application Ser. No. 12/121,552 filed May 15,2008 and entitled “Real-Time Predictive Systems for Intelligent EnergyMonitoring and Management of Electrical Power Networks,” which in turnclaims priority as a Continuation-In-Part under 35 U.S.C. §120 to U.S.patent application Ser. No. 11/777,121 filed Jul. 12, 2007 and entitled“Systems and Methods for Real-Time Advanced Visualization for Predictingthe Health, Reliability, and Performance of an Electrical Power System,”and to U.S. Provisional Patent Application Ser. No. 60/938,324 filed May16, 2007. The disclosures of the above-identified applications areincorporated herein by reference as if set forth in full.

BACKGROUND

1. Technical Field

The present invention relates generally to computer modeling andmanagement of systems and, more particularly, to a Client-ServerApplication Framework for energy management systems for monitoring andmanaging the cost, quality, reliability of an electrical power system.

2. Related Art

Computer models of complex systems enable improved system design,development, and implementation through techniques for off-linesimulation of system operation. That is, system models can be created oncomputers and then “operated” in a virtual environment to assist in thedetermination of system design parameters. All manner of systems can bemodeled, designed, and operated in this way, including machinery,factories, electrical power and distribution systems, processing plants,devices, chemical processes, biological systems, and the like. Suchsimulation techniques have resulted in reduced development costs andsuperior operation.

Design and production processes have benefited greatly from suchcomputer simulation techniques, and such techniques are relatively welldeveloped, but they have not been applied in real-time, e.g., forreal-time operational monitoring and management. In addition, predictivefailure analysis techniques do not generally use real-time data thatreflect actual system operation. Greater efforts at real-timeoperational monitoring and management would provide more accurate andtimely suggestions for operational decisions, and such techniquesapplied to failure analysis would provide improved predictions of systemproblems before they occur.

That is, an electrical network model that can age and synchronize itselfin real-time with the actual facility's operating conditions is criticalto obtaining predictions that are reflective of the system'sreliability, availability, health and performance in relation to thelife cycle of the system. Static systems simply cannot adjust to themany daily changes to the electrical system that occur at a facility(e.g., motors and pumps switching on or off, changes to on-sitegeneration status, changes to utility electrical feed . . . etc.) norcan they age with the facility to accurately predict the requiredindices. Without a synchronization or aging ability, reliability indicesand predictions are of little value as they are not reflective of theactual operational status of the facility and may lead to falseconclusions. With such improved techniques, operational costs and riskscan be greatly reduced.

For example, mission critical electrical systems, e.g., for data centersor nuclear power facilities, must be designed to ensure that power isalways available. Thus, the systems must be as failure proof aspossible, and many layers of redundancy must be designed in to ensurethat there is always a backup in case of a failure. It will beunderstood that such systems are highly complex, a complexity made evengreater as a result of the required redundancy. Computer design andmodeling programs allow for the design of such systems by allowing adesigner to model the system and simulate its operation. Thus, thedesigner can ensure that the system will operate as intended before thefacility is constructed.

As with all analytical tools, predictive or otherwise, the manner inwhich data and results are communicated to the user is often asimportant as the choice of analytical tool itself. Ideally, the data andresults are communicated in a fashion that is simple to understand whilealso painting a comprehensive and accurate picture for the user. Forexample, graphical displays (e.g., two-dimensional and three-dimensionalviews) of the operational aspects of an electrical system greatlyenhances the ability of a system operator, owner and/or executive tounderstand the health and predicted performance of the electricalsystem.

Moreover, the unremitting rise in the costs of generating and/orprocuring energy necessitates pro-actively and intelligently managingenergy through technological solutions that allow energy to be treatedas a business critical commodity that can be managed in real-time whilealso extending the tools that electrical system/network owners andoperators need to observe, comprehend and manage the cost, quality andreliability of energy.

Currently, no solution exists that provide a facility owner,administrator and/or operator with an instant view of the real-time,predicted and/or historical energy consumption profile of an electricalsystem, the cost of energy, the cost of losses and the cost of runningthe electrical system inefficiently.

Furthermore, current simulation technologies are PC or thick clientapplications that require the installation and management of desktopsoftware in order to operate. Currently, no existing solutions takeadvantage of the next generation Web. 2.0 workplace and they fail todeliver a set of rich power system design, analysis Internetapplications (RIAs) to substantially improve the way power systemengineers create and access content, complete sizing and calculations,and produce reports.

SUMMARY

Systems and methods for a client/server application framework that canprovide intelligent monitoring and management of an electrical systemare disclosed.

According to one aspect, a system for intelligent web-based managementof an electrical system, can comprise a data acquisition componentcommunicatively connected to a sensor configured to acquire real-timedata output from the electrical system; a web application servercommunicatively connected to the data acquisition component, the webapplication server configured to transmit a user interface to a clientterminal, the web application server comprising: a virtual system modeldatabase communicatively connected to the data acquisition component,the virtual system model database configured to store a virtual systemmodel of the electrical system, a power analytic simulation enginecomprising a virtual system modeling engine communicatively connected tothe virtual system model database, the virtual system modeling engineconfigured to generate a predicted data output for the electrical systemutilizing the virtual system model of the electrical system, and ananalytics engine communicatively connected to the virtual system modeldatabase, the analytics engine configured to monitor the real-time dataoutput and the predicted data output of the electrical system, and toinitiate a calibration and synchronization operation to update thevirtual system model when a difference between the real-time data outputand the predicted data output exceeds a threshold, and a client terminalcommunicatively connected to the web application server, the clientterminal configured to display the user interface.

According to another aspect, a method for interacting with an electricalsystem management application to perform power analytic analysissimulations on a virtual system model of the electrical power system,can comprise: a web application server, receiving a user request toaccess the electrical management system from a client terminal, andsending a user interface for interaction with the electrical managementsystem to a client terminal; the client terminal, receiving the userinterface for interaction with the electrical management system, andsending user interaction data to the electrical system managementapplication; and, the electrical system management application,performing analytic analysis on a virtual system model of the electricalpower system.

These and other features, aspects, and embodiments are described belowin the section entitled “Detailed Description.”

BRIEF DESCRIPTION OF THE DRAWINGS

Features, aspects, and embodiments are described in conjunction with theattached drawings, in which:

For a more complete understanding of the principles disclosed herein,and the advantages thereof, reference is now made to the followingdescriptions taken in conjunction with the accompanying drawings, inwhich:

FIG. 1 is an illustration of a system for utilizing real-time data forpredictive analysis of the performance of a monitored system, inaccordance with one embodiment.

FIG. 2 is a diagram illustrating a detailed view of an analytics serverincluded in the system of FIG. 1, in accordance with one embodiment.

FIG. 3 is a diagram illustrating how the system of FIG. 1 operates tosynchronize the operating parameters between a physical facility and avirtual system model of the facility, in accordance with one embodiment.

FIG. 4 is an illustration of the scalability of a system for utilizingreal-time data for predictive analysis of the performance of a monitoredsystem, in accordance with one embodiment.

FIG. 5 is a block diagram that shows the configuration details of thesystem illustrated in FIG. 1, in accordance with one embodiment.

FIG. 6 is an illustration of a flowchart describing a method forreal-time monitoring and predictive analysis of a monitored system, inaccordance with one embodiment.

FIG. 7 is an illustration of a flowchart describing a method formanaging real-time updates to a virtual system model of a monitoredsystem, in accordance with one embodiment.

FIG. 8 is an illustration of a flowchart describing a method forsynchronizing real-time system data with a virtual system model of amonitored system, in accordance with one embodiment.

FIG. 9 is a flow chart illustrating an example method for updating thevirtual model, in accordance with one embodiment.

FIG. 10 is a diagram illustrating an example process for monitoring thestatus of protective devices in a monitored system and updating avirtual model based on monitored data, in accordance with oneembodiment.

FIG. 11 is a flowchart illustrating an example process for determiningthe protective capabilities of the protective devices being monitored,in accordance with one embodiment.

FIG. 12 is a diagram illustrating an example process for determining theprotective capabilities of a High Voltage Circuit Breaker (HVCB), inaccordance with one embodiment.

FIG. 13 is a flowchart illustrating an example process for determiningthe protective capabilities of the protective devices being monitored,in accordance with another embodiment.

FIG. 14 is a diagram illustrating a process for evaluating the withstandcapabilities of a MVCB, in accordance with one embodiment

FIG. 15 is a flow chart illustrating an example process for analyzingthe reliability of an electrical power distribution and transmissionsystem, in accordance with one embodiment.

FIG. 16 is a flow chart illustrating an example process for analyzingthe reliability of an electrical power distribution and transmissionsystem that takes weather information into account, in accordance withone embodiment.

FIG. 17 is a diagram illustrating an example process for predicting inreal-time various parameters associated with an alternating current (AC)arc flash incident, in accordance with one embodiment.

FIG. 18 is a flow chart illustrating an example process for real-timeanalysis of the operational stability of an electrical powerdistribution and transmission system, in accordance with one embodiment.

FIG. 19 is a flow chart illustrating an example process for conducting areal-time power capacity assessment of an electrical power distributionand transmission system, in accordance with one embodiment.

FIG. 20 is a flow chart illustrating an example process for performingreal-time harmonics analysis of an electrical power distribution andtransmission system, in accordance with one embodiment.

FIG. 21 is a diagram illustrating how the HTM Pattern Recognition andMachine Learning Engine works in conjunction with the other elements ofthe analytics system to make predictions about the operational aspectsof a monitored system, in accordance with one embodiment.

FIG. 22 is an illustration of the various cognitive layers that comprisethe neocortical catalyst process used by the HTM Pattern Recognition andMachine Learning Engine to analyze and make predictions about theoperational aspects of a monitored system, in accordance with oneembodiment.

FIG. 23 is an example process for real-time three-dimensional (3D)visualization of the health, reliability, and performance of anelectrical system, in accordance with one embodiment.

FIG. 24 is a diagram illustrating how the 3D Visualization Engine worksin conjunction with the other elements of the analytics system toprovide 3D visualization of the health, reliability, and performance ofan electrical system, in accordance with one embodiment.

FIG. 25 provides a client terminal screenshot of some 2D and 3D modelviews that are generated by the power analytics server, in accordancewith one embodiment.

FIG. 26 is a diagram illustrating how the Schematic Interface CreatorEngine works in conjunction with the other elements of the analyticssystem to automatically generate a schematic user interface forvisualizing the health, reliability, and performance of an electricalsystem, in accordance with one embodiment.

FIG. 27 is an example process for automatically generating a schematicuser interface for visualizing the health, reliability, and performanceof an electrical system, in accordance with one embodiment.

FIG. 28 is a diagram illustrating how the Energy Management SystemEngine works in conjunction with the other elements of the analyticssystem to intelligently monitor and manage the cost, quality andreliability of energy generated and/or utilized by an electrical system,in accordance with one embodiment.

FIG. 29 is a logic flow diagram depicting how the various elements ofthe Energy Management System can interact to provide intelligent energymonitoring and management of an electrical system, in accordance withone embodiment.

FIG. 30 is a diagram illustrating how the various elements of theClient/Server system can interact to provide intelligent energymonitoring and management of an electrical system, in accordance withone embodiment.

FIG. 31 is a diagram illustrating various elements of the webapplication server illustrated in FIG. 30, in accordance with oneembodiment.

FIG. 32 is a logic flow diagram depicting how the various elements ofthe Client/Server system can interact to provide intelligent energymonitoring and management of an electrical system, in accordance withone embodiment.

DETAILED DESCRIPTION

Systems and methods for a client/server application framework that canprovide intelligent monitoring and management of an electrical systemare disclosed. It will be clear, however, that the present invention maybe practiced without some or all of these specific details. In otherinstances, well known process operations have not been described indetail in order not to unnecessarily obscure the present invention.

As used herein, a system denotes a set of components, real or abstract,comprising a whole where each component interacts with or is related toat least one other component within the whole. Examples of systemsinclude machinery, factories, electrical systems, processing plants,devices, chemical processes, biological systems, data centers, aircraftcarriers, and the like. An electrical system can designate a powergeneration and/or distribution system that is widely dispersed (i.e.,power generation, transformers, and/or electrical distributioncomponents distributed geographically throughout a large region) orbounded within a particular location (e.g., a power plant within aproduction facility, a bounded geographic area, on board a ship, afactory, a data center, etc.).

A network application is any application that is stored on anapplication server connected to a network (e.g., local area network,wide area network, etc.) in accordance with any contemporaryclient/server architecture model and can be accessed via the network. Inthis arrangement, the network application programming interface (API)resides on the application server separate from the client machine. Theclient interface would typically be a web browser (e.g. INTERNETEXPLORER™, FIREFOX™, NETSCAPE™, etc) that is in communication with thenetwork application server via a network connection (e.g., HTTP, HTTPS,RSS, etc.).

FIG. 1 is an illustration of a system for utilizing real-time data forpredictive analysis of the performance of a monitored system, inaccordance with one embodiment. As shown herein, the system 100 includesa series of sensors (i.e., Sensor A 104, Sensor B 106, Sensor C 108)interfaced with the various components of a monitored system 102, a dataacquisition hub 112, an analytics server 116, and a thin-client device128. In one embodiment, the monitored system 102 is an electrical powergeneration plant. In another embodiment, the monitored system 102 is anelectrical power transmission infrastructure. In still anotherembodiment, the monitored system 102 is an electrical power distributionsystem. In still another embodiment, the monitored system 102 includes acombination of one or more electrical power generation plant(s), powertransmission infrastructure(s), and/or an electrical power distributionsystem. It should be understood that the monitored system 102 can be anycombination of components whose operations can be monitored withconventional sensors and where each component interacts with or isrelated to at least one other component within the combination. For amonitored system 102 that is an electrical power generation,transmission, or distribution system, the sensors can provide data suchas voltage, frequency, current, power, power factor, and the like.

The sensors are configured to provide output values for systemparameters that indicate the operational status and/or “health” of themonitored system 102. For example, in an electrical power generationsystem, the current output or voltage readings for the variouscomponents that comprise the power generation system is indicative ofthe overall health and/or operational condition of the system. In oneembodiment, the sensors are configured to also measure additional datathat can affect system operation. For example, for an electrical powerdistribution system, the sensor output can include environmentalinformation, e.g., temperature, humidity, etc., which can impactelectrical power demand and can also affect the operation and efficiencyof the power distribution system itself.

Continuing with FIG. 1, in one embodiment, the sensors are configured tooutput data in an analog format. For example, electrical power sensormeasurements (e.g., voltage, current, etc.) are sometimes conveyed in ananalog format as the measurements may be continuous in both time andamplitude. In another embodiment, the sensors are configured to outputdata in a digital format. For example, the same electrical power sensormeasurements may be taken in discrete time increments that are notcontinuous in time or amplitude. In still another embodiment, thesensors are configured to output data in either an analog or digitalformat depending on the sampling requirements of the monitored system102.

The sensors can be configured to capture output data at split-secondintervals to effectuate “real time” data capture. For example, in oneembodiment, the sensors can be configured to generate hundreds ofthousands of data readings per second. It should be appreciated,however, that the number of data output readings taken by a sensor maybe set to any value as long as the operational limits of the sensor andthe data processing capabilities of the data acquisition hub 112 are notexceeded.

Still with FIG. 1, each sensor is communicatively connected to the dataacquisition hub 112 via an analog or digital data connection 110. Thedata acquisition hub 112 may be a standalone unit or integrated withinthe analytics server 116 and can be embodied as a piece of hardware,software, or some combination thereof. In one embodiment, the dataconnection 110 is a “hard wired” physical data connection (e.g., serial,network, etc.). For example, a serial or parallel cable connectionbetween the sensor and the hub 112. In another embodiment, the dataconnection 110 is a wireless data connection. For example, a radiofrequency (RF), BLUETOOTH™, infrared or equivalent connection betweenthe sensor and the hub 112.

The data acquisition hub 112 is configured to communicate “real-time”data from the monitored system 102 to the analytics server 116 using anetwork connection 114. In one embodiment, the network connection 114 isa “hardwired” physical connection. For example, the data acquisition hub112 may be communicatively connected (via Category 5 (CAT5), fiber opticor equivalent cabling) to a data server (not shown) that iscommunicatively connected (via CAT5, fiber optic or equivalent cabling)through the Internet and to the analytics server 116 server. Theanalytics server 116 being also communicatively connected with theInternet (via CAT5, fiber optic, or equivalent cabling). In anotherembodiment, the network connection 114 is a wireless network connection(e.g., Wi-Fi, WLAN, etc.). For example, utilizing an 802.11b/g orequivalent transmission format. In practice, the network connectionutilized is dependent upon the particular requirements of the monitoredsystem 102.

Data acquisition hub 112 can also be configured to supply warning andalarms signals as well as control signals to monitored system 102 and/orsensors 104, 106, and 108 as described in more detail below.

As shown in FIG. 1, in one embodiment, the analytics server 116 hosts ananalytics engine 118, virtual system modeling engine 124 and severaldatabases 126, 130, and 132. The virtual system modeling engine can,e.g., be a computer modeling system, such as described above. In thiscontext, however, the modeling engine can be used to precisely model andmirror the actual electrical system. Analytics engine 118 can beconfigured to generate predicted data for the monitored system andanalyze difference between the predicted data and the real-time datareceived from hub 112.

FIG. 2 is a diagram illustrating a more detailed view of analytic server116. As can be seen, analytic server 116 is interfaced with a monitoredfacility 102 via sensors 202, e.g., sensors 104, 106, and 108. Sensors202 are configured to supply real-time data from within monitoredfacility 102. The real-time data is communicated to analytic server 116via a hub 204. Hub 204 can be configure to provide real-time data toserver 116 as well as alarming, sensing and control featured forfacility 102.

The real-time data from hub 204 can be passed to a comparison engine210, which can form part of analytics engine 118. Comparison engine 210can be configured to continuously compare the real-time data withpredicted values generated by simulation engine 208. Based on thecomparison, comparison engine 210 can be further configured to determinewhether deviations between the real-time and the expected values exists,and if so to classify the deviation, e.g., high, marginal, low, etc. Thedeviation level can then be communicated to decision engine 212, whichcan also comprise part of analytics engine 118.

Decision engine 212 can be configured to look for significant deviationsbetween the predicted values and real-time values as received from thecomparison engine 210. If significant deviations are detected, decisionengine 212 can also be configured to determine whether an alarmcondition exists, activate the alarm and communicate the alarm toHuman-Machine Interface (HMI) 214 for display in real-time via, e.g.,thin client 128. Decision engine 212 can also be configured to performroot cause analysis for significant deviations in order to determine theinterdependencies and identify the parent-child failure relationshipsthat may be occurring. In this manner, parent alarm conditions are notdrowned out by multiple children alarm conditions, allowing theuser/operator to focus on the main problem, at least at first.

Thus, in one embodiment, and alarm condition for the parent can bedisplayed via HMI 214 along with an indication that processes andequipment dependent on the parent process or equipment are also in alarmcondition. This also means that server 116 can maintain a parent-childlogical relationship between processes and equipment comprising facility102. Further, the processes can be classified as critical, essential,non-essential, etc.

Decision engine 212 can also be configured to determine health andperformance levels and indicate these levels for the various processesand equipment via HMI 214. All of which, when combined with the analyticcapabilities of analytics engine 118 allows the operator to minimize therisk of catastrophic equipment failure by predicting future failures andproviding prompt, informative information concerning potential/predictedfailures before they occur. Avoiding catastrophic failures reduces riskand cost, and maximizes facility performance and up time.

Simulation engine 208 operates on complex logical models 206 of facility102. These models are continuously and automatically synchronized withthe actual facility status based on the real-time data provided by hub204. In other words, the models are updated based on current switchstatus, breaker status, e.g., open-closed, equipment on/off status, etc.Thus, the models are automatically updated based on such status, whichallows simulation engine to produce predicted data based on the currentfacility status. This in turn, allows accurate and meaningfulcomparisons of the real-time data to the predicted data.

Example models 206 that can be maintained and used by server 116 includepower flow models used to calculate expected kW, kVAR, power factorvalues, etc., short circuit models used to calculate maximum and minimumavailable fault currents, protection models used to determine properprotection schemes and ensure selective coordination of protectivedevices, power quality models used to determine voltage and currentdistortions at any point in the network, to name just a few. It will beunderstood that different models can be used depending on the systembeing modeled.

In certain embodiments, hub 204 is configured to supply equipmentidentification associated with the real-time data. This identificationcan be cross referenced with identifications provided in the models.

In one embodiment, if the comparison performed by comparison engine 210indicates that the differential between the real-time sensor outputvalue and the expected value exceeds a Defined Difference Tolerance(DDT) value (i.e., the “real-time” output values of the sensor output donot indicate an alarm condition) but below an alarm condition (i.e.,alarm threshold value), a calibration request is generated by theanalytics engine 118. If the differential exceeds, the alarm condition,an alarm or notification message is generated by the analytics engine118. If the differential is below the DTT value, the analytics enginedoes nothing and continues to monitor the real-time data and expecteddata.

In one embodiment, the alarm or notification message is sent directly tothe client (i.e., user) 128, e.g., via HMI 214, for display in real-timeon a web browser, pop-up message box, e-mail, or equivalent on theclient 128 display panel. In another embodiment, the alarm ornotification message is sent to a wireless mobile device (e.g.,BLACKBERRY™, laptop, pager, etc.) to be displayed for the user by way ofa wireless router or equivalent device interfaced with the analyticsserver 116. In still another embodiment, the alarm or notificationmessage is sent to both the client 128 display and the wireless mobiledevice. The alarm can be indicative of a need for a repair event ormaintenance to be done on the monitored system. It should be noted,however, that calibration requests should not be allowed if an alarmcondition exists to prevent the models form being calibrated to anabnormal state.

Once the calibration is generated by the analytics engine 118, thevarious operating parameters or conditions of model(s) 206 can beupdated or adjusted to reflect the actual facility configuration. Thiscan include, but is not limited to, modifying the predicted data outputfrom the simulation engine 208, adjusting the logic/processingparameters utilized by the model(s) 206, adding/subtracting functionalelements from model(s) 206, etc. It should be understood, that anyoperational parameter of models 206 can be modified as long as theresulting modifications can be processed and registered by simulationengine 208.

Referring back to FIG. 1, models 206 can be stored in the virtual systemmodel database 126. As noted, a variety of conventional virtual modelapplications can be used for creating a virtual system model, so that awide variety of systems and system parameters can be modeled. Forexample, in the context of an electrical power distribution system, thevirtual system model can include components for modeling reliability,voltage stability, and power flow. In addition, models 206 can includedynamic control logic that permits a user to configure the models 206 byspecifying control algorithms and logic blocks in addition tocombinations and interconnections of generators, governors, relays,breakers, transmission line, and the like. The voltage stabilityparameters can indicate capacity in terms of size, supply, anddistribution, and can indicate availability in terms of remainingcapacity of the presently configured system. The power flow model canspecify voltage, frequency, and power factor, thus representing the“health” of the system.

All of models 206 can be referred to as a virtual system model. Thus,virtual system model database can be configured to store the virtualsystem model. A duplicate, but synchronized copy of the virtual systemmodel can be stored in a virtual simulation model database 130. Thisduplicate model can be used for what-if simulations. In other words,this model can be used to allow a system designer to make hypotheticalchanges to the facility and test the resulting effect, without takingdown the facility or costly and time consuming analysis. Suchhypothetical can be used to learn failure patterns and signatures aswell as to test proposed modifications, upgrades, additions, etc., forthe facility. The real-time data, as well as trending produced byanalytics engine 118 can be stored in a real-time data acquisitiondatabase 132.

As discussed above, the virtual system model is periodically calibratedand synchronized with “real-time” sensor data outputs so that thevirtual system model provides data output values that are consistentwith the actual “real-time” values received from the sensor outputsignals. Unlike conventional systems that use virtual system modelsprimarily for system design and implementation purposes (i.e., offlinesimulation and facility planning), the virtual system models describedherein are updated and calibrated with the real-time system operationaldata to provide better predictive output values. A divergence betweenthe real-time sensor output values and the predicted output valuesgenerate either an alarm condition for the values in question and/or acalibration request that is sent to the calibration engine 134.

Continuing with FIG. 1, the analytics engine 118 can be configured toimplement pattern/sequence recognition into a real-time decision loopthat, e.g., is enabled by a new type of machine learning calledassociative memory, or hierarchical temporal memory (HTM), which is abiological approach to learning and pattern recognition. Associativememory allows storage, discovery, and retrieval of learned associationsbetween extremely large numbers of attributes in real time. At a basiclevel, an associative memory stores information about how attributes andtheir respective features occur together. The predictive power of theassociative memory technology comes from its ability to interpret andanalyze these co-occurrences and to produce various metrics. Associativememory is built through “experiential” learning in which each newlyobserved state is accumulated in the associative memory as a basis forinterpreting future events. Thus, by observing normal system operationover time, and the normal predicted system operation over time, theassociative memory is able to learn normal patterns as a basis foridentifying non-normal behavior and appropriate responses, and toassociate patterns with particular outcomes, contexts or responses. Theanalytics engine 118 is also better able to understand component meantime to failure rates through observation and system availabilitycharacteristics. This technology in combination with the virtual systemmodel can be characterized as a “neocortical” model of the system undermanagement.

This approach also presents a novel way to digest and comprehend alarmsin a manageable and coherent way. The neocortical model could assist inuncovering the patterns and sequencing of alarms to help pinpoint thelocation of the (impending) failure, its context, and even the cause.Typically, responding to the alarms is done manually by experts who havegained familiarity with the system through years of experience. However,at times, the amount of information is so great that an individualcannot respond fast enough or does not have the necessary expertise. An“intelligent” system like the neocortical system that observes andrecommends possible responses could improve the alarm management processby either supporting the existing operator, or even managing the systemautonomously.

Current simulation approaches for maintaining transient stabilityinvolve traditional numerical techniques and typically do not test allpossible scenarios. The problem is further complicated as the numbers ofcomponents and pathways increase. Through the application of theneocortical model, by observing simulations of circuits, and bycomparing them to actual system responses, it may be possible to improvethe simulation process, thereby improving the overall design of futurecircuits.

The virtual system model database 126, as well as databases 130 and 132,can be configured to store one or more virtual system models, virtualsimulation models, and real-time data values, each customized to aparticular system being monitored by the analytics server 118. Thus, theanalytics server 118 can be utilized to monitor more than one system ata time. As depicted herein, the databases 126, 130, and 132 can behosted on the analytics server 116 and communicatively interfaced withthe analytics engine 118. In other embodiments, databases 126, 130, and132 can be hosted on a separate database server (not shown) that iscommunicatively connected to the analytics server 116 in a manner thatallows the virtual system modeling engine 124 and analytics engine 118to access the databases as needed.

Therefore, in one embodiment, the client 128 can modify the virtualsystem model stored on the virtual system model database 126 by using avirtual system model development interface using well-known modelingtools that are separate from the other network interfaces. For example,dedicated software applications that run in conjunction with the networkinterface to allow a client 128 to create or modify the virtual systemmodels.

The client 128 may utilize a variety of network interfaces (e.g., webbrowser, CITRIX™, WINDOWS TERMINAL SERVICES™, telnet, or otherequivalent thin-client terminal applications, etc.) to access,configure, and modify the sensors (e.g., configuration files, etc.),analytics engine 118 (e.g., configuration files, analytics logic, etc.),calibration parameters (e.g., configuration files, calibrationparameters, etc.), virtual system modeling engine 124 (e.g.,configuration files, simulation parameters, etc.) and virtual systemmodel of the system under management (e.g., virtual system modeloperating parameters and configuration files). Correspondingly, datafrom those various components of the monitored system 102 can bedisplayed on a client 128 display panel for viewing by a systemadministrator or equivalent.

As described above, server 116 is configured to synchronize the physicalworld with the virtual and report, e.g., via visual, real-time display,deviations between the two as well as system health, alarm conditions,predicted failures, etc. This is illustrated with the aid of FIG. 3, inwhich the synchronization of the physical world (left side) and virtualworld (right side) is illustrated. In the physical world, sensors 202produce real-time data 302 for the processes 312 and equipment 314 thatmake up facility 102. In the virtual world, simulations 304 of thevirtual system model 206 provide predicted values 306, which arecorrelated and synchronized with the real-time data 302. The real-timedata can then be compared to the predicted values so that differences308 can be detected. The significance of these differences can bedetermined to determine the health status 310 of the system. The healthstats can then be communicated to the processes 312 and equipment 314,e.g., via alarms and indicators, as well as to thin client 128, e.g.,via web pages 316.

FIG. 4 is an illustration of the scalability of a system for utilizingreal-time data for predictive analysis of the performance of a monitoredsystem, in accordance with one embodiment. As depicted herein, ananalytics central server 422 is communicatively connected with analyticsserver A 414, analytics server B 416, and analytics server n 418 (i.e.,one or more other analytics servers) by way of one or more networkconnections 114. Each of the analytics servers is communicativelyconnected with a respective data acquisition hub (i.e., Hub A 408, Hub B410, Hub n 412) that communicates with one or more sensors that areinterfaced with a system (i.e., Monitored System A 402, Monitored SystemB 404, Monitored System n 406) that the respective analytical servermonitors. For example, analytics server A 414 is communicative connectedwith data acquisition hub A 408, which communicates with one or moresensors interfaced with monitored system A 402.

Each analytics server (i.e., analytics server A 414, analytics server B416, analytics server n 418) is configured to monitor the sensor outputdata of its corresponding monitored system and feed that data to thecentral analytics server 422. Additionally, each of the analyticsservers can function as a proxy agent of the central analytics server422 during the modifying and/or adjusting of the operating parameters ofthe system sensors they monitor. For example, analytics server B 416 isconfigured to be utilized as a proxy to modify the operating parametersof the sensors interfaced with monitored system B 404.

Moreover, the central analytics server 422, which is communicativelyconnected to one or more analytics server(s) can be used to enhance thescalability. For example, a central analytics server 422 can be used tomonitor multiple electrical power generation facilities (i.e., monitoredsystem A 402 can be a power generation facility located in city A whilemonitored system B 404 is a power generation facility located in city B)on an electrical power grid. In this example, the number of electricalpower generation facilities that can be monitored by central analyticsserver 422 is limited only by the data processing capacity of thecentral analytics server 422. The central analytics server 422 can beconfigured to enable a client 128 to modify and adjust the operationalparameters of any the analytics servers communicatively connected to thecentral analytics server 422. Furthermore, as discussed above, each ofthe analytics servers are configured to serve as proxies for the centralanalytics server 422 to enable a client 128 to modify and/or adjust theoperating parameters of the sensors interfaced with the systems thatthey respectively monitor. For example, the client 128 can use thecentral analytics server 422, and vice versa, to modify and/or adjustthe operating parameters of analytics server A 414 and utilize the sameto modify and/or adjust the operating parameters of the sensorsinterfaced with monitored system A 402. Additionally, each of theanalytics servers can be configured to allow a client 128 to modify thevirtual system model through a virtual system model developmentinterface using well-known modeling tools.

In one embodiment, the central analytics server 422 can function tomonitor and control a monitored system when its corresponding analyticsserver is out of operation. For example, central analytics server 422can take over the functionality of analytics server B 416 when theserver 416 is out of operation. That is, the central analytics server422 can monitor the data output from monitored system B 404 and modifyand/or adjust the operating parameters of the sensors that areinterfaced with the system 404.

In one embodiment, the network connection 114 is established through awide area network (WAN) such as the Internet. In another embodiment, thenetwork connection is established through a local area network (LAN)such as the company intranet. In a separate embodiment, the networkconnection 114 is a “hardwired” physical connection. For example, thedata acquisition hub 112 may be communicatively connected (via Category5 (CAT5), fiber optic or equivalent cabling) to a data server that iscommunicatively connected (via CAT5, fiber optic or equivalent cabling)through the Internet and to the analytics server 116 server hosting theanalytics engine 118. In another embodiment, the network connection 114is a wireless network connection (e.g., Wi-Fi, WLAN, etc.). For example,utilizing an 802.11b/g or equivalent transmission format.

In certain embodiments, regional analytics servers can be placed betweenlocal analytics servers 414, 416, . . . , 418 and central analyticsserver 422. Further, in certain embodiments a disaster recovery site canbe included at the central analytics server 422 level.

FIG. 5 is a block diagram that shows the configuration details ofanalytics server 116 illustrated in FIG. 1 in more detail. It should beunderstood that the configuration details in FIG. 5 are merely oneembodiment of the items described for FIG. 1, and it should beunderstood that alternate configurations and arrangements of componentscould also provide the functionality described herein.

The analytics server 116 includes a variety of components. In the FIG. 5embodiment, the analytics server 116 is implemented in a Web-basedconfiguration, so that the analytics server 116 includes (orcommunicates with) a secure web server 530 for communication with thesensor systems 519 (e.g., data acquisition units, metering devices,sensors, etc.) and external communication entities 534 (e.g., webbrowser, “thin client” applications, etc.). A variety of user views andfunctions 532 are available to the client 128 such as: alarm reports,Active X controls, equipment views, view editor tool, custom userinterface page, and XML parser. It should be appreciated, however, thatthese are just examples of a few in a long list of views and functions532 that the analytics server 116 can deliver to the externalcommunications entities 534 and are not meant to limit the types ofviews and functions 532 available to the analytics server 116 in anyway.

The analytics server 116 also includes an alarm engine 506 and messagingengine 504, for the aforementioned external communications. The alarmengine 506 is configured to work in conjunction with the messagingengine 504 to generate alarm or notification messages 502 (in the formof text messages, e-mails, paging, etc.) in response to the alarmconditions previously described. The analytics server 116 determinesalarm conditions based on output data it receives from the varioussensor systems 519 through a communications connection (e.g., wireless516, TCP/IP 518, Serial 520, etc) and simulated output data from avirtual system model 512, of the monitored system, processed by theanalytics engines 118. In one embodiment, the virtual system model 512is created by a user through interacting with an external communicationentity 534 by specifying the components that comprise the monitoredsystem and by specifying relationships between the components of themonitored system. In another embodiment, the virtual system model 512 isautomatically generated by the analytics engines 118 as components ofthe monitored system are brought online and interfaced with theanalytics server 508.

Continuing with FIG. 5, a virtual system model database 526 iscommunicatively connected with the analytics server 116 and isconfigured to store one or more virtual system models 512, each of whichrepresents a particular monitored system. For example, the analyticsserver 116 can conceivably monitor multiple electrical power generationsystems (e.g., system A, system B, system C, etc.) spread across a widegeographic area (e.g., City A, City B, City C, etc.). Therefore, theanalytics server 116 will utilize a different virtual system model 512for each of the electrical power generation systems that it monitors.Virtual simulation model database 538 can be configured to store asynchronized, duplicate copy of the virtual system model 512, andreal-time data acquisition database 540 can store the real-time andtrending data for the system(s) being monitored.

Thus, in operation, analytics server 116 can receive real-time data forvarious sensors, i.e., components, through data acquisition system 202.As can be seen, analytics server 116 can comprise various driversconfigured to interface with the various types of sensors, etc.,comprising data acquisition system 202. This data represents thereal-time operational data for the various components. For example, thedata may indicate that a certain component is operating at a certainvoltage level and drawing certain amount of current. This informationcan then be fed to a modeling engine to generate a virtual system model612 that is based on the actual real-time operational data.

Analytics engine 118 can be configured to compare predicted data basedon the virtual system model 512 with real-time data received from dataacquisition system 202 and to identify any differences. In someinstances, analytics engine can be configured to identify thesedifferences and then update, i.e., calibrate, the virtual system model512 for use in future comparisons. In this manner, more accuratecomparisons and warnings can be generated.

But in other instances, the differences will indicate a failure, or thepotential for a failure. For example, when a component begins to fail,the operating parameters will begin to change. This change may be suddenor it may be a progressive change over time. Analytics engine 118 candetect such changes and issue warnings that can allow the changes to bedetected before a failure occurs. The analytic engine 118 can beconfigured to generate warnings that can be communicated via interface532.

For example, a user can access information from server 116 using thinclient 534. For example, reports can be generate and served to thinclient 534 via server 540. These reports can, for example, compriseschematic or symbolic illustrations of the system being monitored.Status information for each component can be illustrated or communicatedfor each component. This information can be numerical, i.e., the voltageor current level. Or it can be symbolic, i.e., green for normal, red forfailure or warning. In certain embodiments, intermediate levels offailure can also be communicated, i.e., yellow can be used to indicateoperational conditions that project the potential for future failure. Itshould be noted that this information can be accessed in real-time.Moreover, via thin client 534, the information can be accessed formanywhere and anytime.

Continuing with FIG. 5, the Analytics Engine 118 is communicativelyinterfaced with a HTM Pattern Recognition and Machine Learning Engine551. The HTM Engine 551 is configured to work in conjunction with theAnalytics Engine 118 and a virtual system model of the monitored systemto make real-time predictions (i.e., forecasts) about variousoperational aspects of the monitored system. The HTM Engine 551 works byprocessing and storing patterns observed during the normal operation ofthe monitored system over time. These observations are provided in theform of real-time data captured using a multitude of sensors that areimbedded within the monitored system. In one embodiment, the virtualsystem model is also updated with the real-time data such that thevirtual system model “ages” along with the monitored system. Examples ofa monitored system includes machinery, factories, electrical systems,processing plants, devices, chemical processes, biological systems, datacenters, aircraft carriers, and the like. It should be understood thatthe monitored system can be any combination of components whoseoperations can be monitored with conventional sensors and where eachcomponent interacts with or is related to at least one other componentwithin the combination.

FIG. 6 is an illustration of a flowchart describing a method forreal-time monitoring and predictive analysis of a monitored system, inaccordance with one embodiment. Method 600 begins with operation 602where real-time data indicative of the monitored system status isprocessed to enable a virtual model of the monitored system undermanagement to be calibrated and synchronized with the real-time data. Inone embodiment, the monitored system 102 is a mission criticalelectrical power system. In another embodiment, the monitored system 102can include an electrical power transmission infrastructure. In stillanother embodiment, the monitored system 102 includes a combination ofthereof. It should be understood that the monitored system 102 can beany combination of components whose operations can be monitored withconventional sensors and where each component interacts with or isrelated to at least one other component within the combination.

Method 600 moves on to operation 604 where the virtual system model ofthe monitored system under management is updated in response to thereal-time data. This may include, but is not limited to, modifying thesimulated data output from the virtual system model, adjusting thelogic/processing parameters utilized by the virtual system modelingengine to simulate the operation of the monitored system,adding/subtracting functional elements of the virtual system model, etc.It should be understood, that any operational parameter of the virtualsystem modeling engine and/or the virtual system model may be modifiedby the calibration engine as long as the resulting modifications can beprocessed and registered by the virtual system modeling engine.

Method 600 proceeds on to operation 606 where the simulated real-timedata indicative of the monitored system status is compared with acorresponding virtual system model created at the design stage. Thedesign stage models, which may be calibrated and updated based onreal-time monitored data, are used as a basis for the predictedperformance of the system. The real-time monitored data can then providethe actual performance over time. By comparing the real-time time datawith the predicted performance information, difference can be identifieda tracked by, e.g., the analytics engine 118. Analytics engines 118 canthen track trends, determine alarm states, etc., and generate areal-time report of the system status in response to the comparison.

In other words, the analytics can be used to analyze the comparison andreal-time data and determine if there is a problem that should bereported and what level the problem may be, e.g., low priority, highpriority, critical, etc. The analytics can also be used to predictfuture failures and time to failure, etc. In one embodiment, reports canbe displayed on a conventional web browser (e.g. INTERNET EXPLORER™,FIREFOX™, NETSCAPE™, etc) that is rendered on a standard personalcomputing (PC) device. In another embodiment, the “real-time” report canbe rendered on a “thin-client” computing device (e.g., CITRIX™, WINDOWSTERMINAL SERVICES™, telnet, or other equivalent thin-client terminalapplication). In still another embodiment, the report can be displayedon a wireless mobile device (e.g., BLACKBERRY™, laptop, pager, etc.).For example, in one embodiment, the “real-time” report can include suchinformation as the differential in a particular power parameter (i.e.,current, voltage, etc.) between the real-time measurements and thevirtual output data.

FIG. 7 is an illustration of a flowchart describing a method formanaging real-time updates to a virtual system model of a monitoredsystem, in accordance with one embodiment. Method 700 begins withoperation 702 where real-time data output from a sensor interfaced withthe monitored system is received. The sensor is configured to captureoutput data at split-second intervals to effectuate “real time” datacapture. For example, in one embodiment, the sensor is configured togenerate hundreds of thousands of data readings per second. It should beappreciated, however, that the number of data output readings taken bythe sensor may be set to any value as long as the operational limits ofthe sensor and the data processing capabilities of the data acquisitionhub are not exceeded.

Method 700 moves to operation 704 where the real-time data is processedinto a defined format. This would be a format that can be utilized bythe analytics server to analyze or compare the data with the simulateddata output from the virtual system model. In one embodiment, the datais converted from an analog signal to a digital signal. In anotherembodiment, the data is converted from a digital signal to an analogsignal. It should be understood, however, that the real-time data may beprocessed into any defined format as long as the analytics engine canutilize the resulting data in a comparison with simulated output datafrom a virtual system model of the monitored system.

Method 700 continues on to operation 706 where the predicted (i.e.,simulated) data for the monitored system is generated using a virtualsystem model of the monitored system. As discussed above, a virtualsystem modeling engine utilizes dynamic control logic stored in thevirtual system model to generate the predicted output data. Thepredicted data is supposed to be representative of data that shouldactually be generated and output from the monitored system.

Method 700 proceeds to operation 708 where a determination is made as towhether the difference between the real-time data output and thepredicted system data falls between a set value and an alarm conditionvalue, where if the difference falls between the set value and the alarmcondition value a virtual system model calibration and a response can begenerated. That is, if the comparison indicates that the differentialbetween the “real-time” sensor output value and the corresponding“virtual” model data output value exceeds a Defined Difference Tolerance(DDT) value (i.e., the “real-time” output values of the sensor output donot indicate an alarm condition) but below an alarm condition (i.e.,alarm threshold value), a response can be generated by the analyticsengine. In one embodiment, if the differential exceeds, the alarmcondition, an alarm or notification message is generated by theanalytics engine 118. In another embodiment, if the differential isbelow the DTT value, the analytics engine does nothing and continues tomonitor the “real-time” data and “virtual” data. Generally speaking, thecomparison of the set value and alarm condition is indicative of thefunctionality of one or more components of the monitored system.

FIG. 8 is an illustration of a flowchart describing a method forsynchronizing real-time system data with a virtual system model of amonitored system, in accordance with one embodiment. Method 800 beginswith operation 802 where a virtual system model calibration request isreceived. A virtual model calibration request can be generated by ananalytics engine whenever the difference between the real-time dataoutput and the predicted system data falls between a set value and analarm condition value.

Method 800 proceeds to operation 804 where the predicted system outputvalue for the virtual system model is updated with a real-time outputvalue for the monitored system. For example, if sensors interfaced withthe monitored system outputs a real-time current value of A, then thepredicted system output value for the virtual system model is adjustedto reflect a predicted current value of A.

Method 800 moves on to operation 806 where a difference between thereal-time sensor value measurement from a sensor integrated with themonitored system and a predicted sensor value for the sensor isdetermined. As discussed above, the analytics engine is configured toreceive “real-time” data from sensors interfaced with the monitoredsystem via the data acquisition hub (or, alternatively directly from thesensors) and “virtual” data from the virtual system modeling enginesimulating the data output from a virtual system model of the monitoredsystem. In one embodiment, the values are in units of electrical poweroutput (i.e., current or voltage) from an electrical power generation ortransmission system. It should be appreciated, however, that the valuescan essentially be any unit type as long as the sensors can beconfigured to output data in those units or the analytics engine canconvert the output data received from the sensors into the desired unittype before performing the comparison.

Method 800 continues on to operation 808 where the operating parametersof the virtual system model are adjusted to minimize the difference.This means that the logic parameters of the virtual system model that avirtual system modeling engine uses to simulate the data output fromactual sensors interfaced with the monitored system are adjusted so thatthe difference between the real-time data output and the simulated dataoutput is minimized. Correspondingly, this operation will update andadjust any virtual system model output parameters that are functions ofthe virtual system model sensor values. For example, in a powerdistribution environment, output parameters of power load or demandfactor might be a function of multiple sensor data values. The operatingparameters of the virtual system model that mimic the operation of thesensor will be adjusted to reflect the real-time data received fromthose sensors. In one embodiment, authorization from a systemadministrator is requested prior to the operating parameters of thevirtual system model being adjusted. This is to ensure that the systemadministrator is aware of the changes that are being made to the virtualsystem model. In one embodiment, after the completion of all the variouscalibration operations, a report is generated to provide a summary ofall the adjustments that have been made to the virtual system model.

As described above, virtual system modeling engine 124 can be configuredto model various aspects of the system to produce predicted values forthe operation of various components within monitored system 102. Thesepredicted values can be compared to actual values being received viadata acquisition hub 112. If the differences are greater than a certainthreshold, e.g., the DTT, but not in an alarm condition, then acalibration instruction can be generated. The calibration instructioncan cause a calibration engine 134 to update the virtual model beingused by system modeling engine 124 to reflect the new operatinginformation.

It will be understood that as monitored system 102 ages, or morespecifically the components comprising monitored system 102 age, thenthe operating parameters, e.g., currents and voltages associated withthose components will also change. Thus, the process of calibrating thevirtual model based on the actual operating information provides amechanism by which the virtual model can be aged along with themonitored system 102 so that the comparisons being generated byanalytics engine 118 are more meaningful.

At a high level, this process can be illustrated with the aid of FIG. 9,which is a flow chart illustrating an example method for updating thevirtual model in accordance with one embodiment. In step 902, data iscollected from, e.g., sensors 104, 106, and 108. For example, thesensors can be configured to monitor protective devices within anelectrical distribution system to determine and monitor the ability ofthe protective devices to withstand faults, which is describe in moredetail below.

In step 904, the data from the various sensors can be processed byanalytics engine 118 in order to evaluate various parameters related tomonitored system 102. In step 905, simulation engine 124 can beconfigured to generate predicted values for monitored system 102 using avirtual model of the system that can be compared to the parametersgenerated by analytics engine 118 in step 904. If there are differencesbetween the actual values and the predicted values, then the virtualmodel can be updated to ensure that the virtual model ages with theactual system 102.

It should be noted that as the monitored system 102 ages, variouscomponents can be repaired, replaced, or upgraded, which can also createdifferences between the simulated and actual data that is not an alarmcondition. Such activity can also lead to calibrations of the virtualmodel to ensure that the virtual model produces relevant predictedvalues. Thus, not only can the virtual model be updated to reflect agingof monitored system 102, but it can also be updated to reflectretrofits, repairs, etc.

As noted above, in certain embodiments, a logical model of a facilitieselectrical system, a data acquisition system (data acquisition hub 112),and power system simulation engines (modeling engine 124) can beintegrated with a logic and methods based approach to the adjustment ofkey database parameters within a virtual model of the electrical systemto evaluate the ability of protective devices within the electricaldistribution system to withstand faults and also effectively “age” thevirtual system with the actual system.

Only through such a process can predictions on the withstand abilitiesof protective devices, and the status, security and health of anelectrical system be accurately calculated. Accuracy is important as thepredictions can be used to arrive at actionable, mission critical orbusiness critical conclusions that may lead to the re-alignment of theelectrical distribution system for optimized performance or security.

FIGS. 10-12 are flow charts presenting logical flows for determining theability of protective devices within an electrical distribution systemto withstand faults and also effectively “age” the virtual system withthe actual system in accordance with one embodiment. FIG. 10 is adiagram illustrating an example process for monitoring the status ofprotective devices in a monitored system 102 and updating a virtualmodel based on monitored data. First, in step 1002, the status of theprotective devices can be monitored in real time. As mentioned,protective devices can include fuses, switches, relays, and circuitbreakers. Accordingly, the status of the fuses/switches, relays, and/orcircuit breakers, e.g., the open/close status, source and load status,and on or off status, can be monitored in step 1002. It can bedetermined, in step 1004, if there is any change in the status of themonitored devices. If there is a change, then in step 1006, the virtualmodel can be updated to reflect the status change, i.e., thecorresponding virtual components data can be updated to reflect theactual status of the various protective devices.

In step 1008, predicted values for the various components of monitoredsystem 102 can be generated. But it should be noted that these valuesare based on the current, real-time status of the monitored system. Realtime sensor data can be received in step 1012. This real time data canbe used to monitor the status in step 1002 and it can also be comparedwith the predicted values in step 1014. As noted above, the differencebetween the predicted values and the real time data can also bedetermined in step 1014.

Accordingly, meaningful predicted values based on the actual conditionof monitored system 102 can be generated in steps 1004 to 1010. Thesepredicted values can then be used to determine if further action shouldbe taken based on the comparison of step 1014. For example, if it isdetermined in step 1016 that the difference between the predicted valuesand the real time sensor data is less than or equal to a certainthreshold, e.g., DTT, then no action can be taken e.g., an instructionnot to perform calibration can be issued in step 1018. Alternatively, ifit is determined in step 1020 that the real time data is actuallyindicative of an alarm situation, e.g., is above an alarm threshold,then a do not calibrate instruction can be generated in step 1018 and analarm can be generated as described above. If the real time sensor datais not indicative of an alarm condition, and the difference between thereal time sensor data and the predicted values is greater than thethreshold, as determined in step 1022, then an initiate calibrationcommand can be generated in step 1024.

If an initiate calibration command is issued in step 1024, then afunction call to calibration engine 134 can be generated in step 1026.The function call will cause calibration engine 134 to update thevirtual model in step 1028 based on the real time sensor data. Acomparison between the real time data and predicted data can then begenerated in step 1030 and the differences between the two computed. Instep 1032, a user can be prompted as to whether or not the virtual modelshould in fact be updated. In other embodiments, the update can beautomatic, and step 1032 can be skipped. In step 1034, the virtual modelcould be updated. For example, the virtual model loads, buses, demandfactor, and/or percent running information can be updated based on theinformation obtained in step 1030. An initiate simulation instructioncan then be generated in step 1036, which can cause new predicted valuesto be generated based on the update of virtual model.

In this manner, the predicted values generated in step 1008 are not onlyupdated to reflect the actual operational status of monitored system102, but they are also updated to reflect natural changes in monitoredsystem 102 such as aging. Accordingly, realistic predicted values can begenerated in step 1008.

FIG. 11 is a flowchart illustrating an example process for determiningthe protective capabilities of the protective devices being monitored instep 1002. Depending on the embodiment, the protective devices can beevaluated in terms of the International Electrotechnical Commission(IEC) standards or in accordance with the United States or AmericanNational Standards Institute (ANSI) standards. It will be understood,that the process described in relation to FIG. 11 is not dependent on aparticular standard being used.

First, in step 1102, a short circuit analysis can be performed for theprotective device. Again, the protective device can be any one of avariety of protective device types. For example, the protective devicecan be a fuse or a switch, or some type of circuit breaker. It will beunderstood that there are various types of circuit breakers includingLow Voltage Circuit Breakers (LVCBs), High Voltage Circuit Breakers(HVCBs), Mid Voltage Circuit Breakers (MVCBs), Miniature CircuitBreakers (MCBs), Molded Case Circuit Breakers (MCCBs), Vacuum CircuitBreakers, and Air Circuit Breakers, to name just a few. Any one of thesevarious types of protective devices can be monitored and evaluated usingthe processes illustrated with respect to FIGS. 10-12.

For example, for LVCBs, or MCCBs, the short circuit current, symmetric(I_(sym)) or asymmetric (I_(asym)), and/or the peak current (I_(peak))can be determined in step 1102. For, e.g., LVCBs that are notinstantaneous trip circuit breakers, the short circuit current at adelayed time (I_(symdelay)) can be determined. For HVCBs, a first cycleshort circuit current (I_(sym)) and/or I_(peak) can be determined instep 1102. For fuses or switches, the short circuit current, symmetricor asymmetric, can be determined in step 1102. And for MVCBs the shortcircuit current interrupting time can be calculated. These are just someexamples of the types of short circuit analysis that can be performed inStep 1102 depending on the type of protective device being analyzed.

Once the short circuit analysis is performed in step 1102, various stepscan be carried out in order to determine the bracing capability of theprotective device. For example, if the protective device is a fuse orswitch, then the steps on the left hand side of FIG. 11 can be carriedout. In this case, the fuse rating can first be determined in step 1104.In this case, the fuse rating can be the current rating for the fuse.For certain fuses, the X/R can be calculated in step 1105 and theasymmetric short circuit current (I_(asym)) for the fuse can bedetermined in step 1106 using equation 1.I _(ASYM) =I _(SYM)√{square root over (1+2e ^(−2p/(X/R)))}  Eq 1

In other implementations, the inductants/reactants (X/R) ratio can becalculated in step 1108 and compared to a fuse test X/R to determine ifthe calculated X/R is greater than the fuse test X/R. The calculated X/Rcan be determined using the predicted values provided in step 1008.Various standard tests X/R values can be used for the fuse test X/Rvalues in step 1108. For example, standard test X/R values for a LVCBcan be as follows:

PCB, ICCB = 6.59 MCCB, ICCB  rated <  = 10, 000  A = 1.73MCCB, ICCB  rated  10, 001 − 20, 000  A = 3.18MCCB, ICCB  rated > 20, 000  A = 4.9

If the calculated X/R is greater than the fuse test X/R, then in step1112, equation 12 can be used to calculate an adjusted symmetrical shortcircuit current (I_(adjsym)).

$\begin{matrix}{I_{ADJSYM} = {I_{SYM}\left\{ \frac{\sqrt{1 + {2{\mathbb{e}}^{{- 2}{p/{({{CALC}\mspace{14mu}{X/R}})}}}}}}{\sqrt{1 + {2{\mathbb{e}}^{{- 2}{p/{({{TEST}\mspace{14mu}{X/R}})}}}}}} \right\}}} & {{Eq}\mspace{14mu} 12}\end{matrix}$

If the calculated X/R is not greater than the fuse test X/R thenI_(adjsym) can be set equal to I_(sym) in step 1110. In step 1114, itcan then be determined if the fuse rating (step 1104) is greater than orequal to I_(adjsym) or I_(asym). If it is, then it can determine in step1118 that the protected device has passed and the percent rating can becalculated in step 1120 as follows:

${\%\mspace{14mu}{rating}} = {{\frac{I_{ADJSYM}}{{Device}\mspace{14mu}{rating}}\mspace{14mu}{or}\mspace{14mu}\%\mspace{14mu}{rating}} = \frac{I_{ASYM}}{{Device}\mspace{14mu}{rating}}}$

If it is determined in step 1114 that the device rating is not greaterthan or equal to I_(adjsym), then it can be determined that the deviceas failed in step 1116. The percent rating can still be calculating instep 1120.

For LVCBs, it can first be determined whether they are fused in step1122. If it is determined that the LVCB is not fused, then in step 1124can be determined if the LVCB is an instantaneous trip LVCB. If it isdetermined that the LVCB is an instantaneous trip LVCB, then in step1130 the first cycle fault X/R can be calculated and compared to acircuit breaker test X/R (see example values above) to determine if thefault X/R is greater than the circuit breaker test X/R. If the fault X/Ris not greater than the circuit breaker test X/R, then in step 1132 itcan be determined if the LVCB is peak rated. If it is peak rated, thenI_(peak) can be used in step 1146 below. If it is determined that theLVCB is not peak rated in step 1132, then I_(adjsym) can be set equal toI_(sym) in step 1140. In step 1146, it can be determined if the devicerating is greater or equal to I_(adjsym), or to I_(peak) as appropriate,for the LVCB.

If it is determined that the device rating is greater than or equal toI_(adjsym), then it can be determined that the LVCB has passed in step1148. The percent rating can then be determined using the equations forI_(adjsym) defined above (step 1120) in step 1152. If it is determinedthat the device rating is not greater than or equal to I_(adjsym), thenit can be determined that the device has failed in step 1150. Thepercent rating can still be calculated in step 1152.

If the calculated fault X/R is greater than the circuit breaker test X/Ras determined in step 1130, then it can be determined if the LVCB ispeak rated in step 1134. If the LVCB is not peak rated, then theI_(adjsym) can be determined using equation 12. If the LVCB is peakrated, then I_(peak) can be determined using equation 11.I _(PEAK)=√{square root over (2)}I _(SYM){1.02+0.98e ^(−3/(X/R))}  Eq 11

It can then be determined if the device rating is greater than or equalto I_(adjsym) or I_(peak) as appropriate. The pass/fail determinationscan then be made in steps 1148 and 1150 respectively, and the percentrating can be calculated in step 1152.

${\%\mspace{14mu}{rating}} = {{\frac{I_{ADJSYM}}{{Device}\mspace{14mu}{rating}}\mspace{14mu}{or}\mspace{14mu}\%\mspace{14mu}{rating}} = \frac{I_{PEAK}}{{Device}\mspace{14mu}{rating}}}$

If the LVCB is not an instantaneous trip LVCB as determined in step1124, then a time delay calculation can be performed at step 1128followed by calculation of the fault X/R and a determination of whetherthe fault X/R is greater than the circuit breaker test X/R. If it isnot, then Iadjsym can be set equal to Isym in step 1136. If thecalculated fault at X/R is greater than the circuit breaker test X/R,then Iadjsymdelay can be calculated in step 1138 using the followingequation with, e.g., a 0.5 second maximum delay:

$\begin{matrix}{I_{\underset{DELAY}{ADJSYM}} = {I_{\underset{DELAY}{SYM}}\left\{ \frac{\sqrt{1 + {2{\mathbb{e}}^{{- 60}{p/{({{CALC}\mspace{14mu}{X/R}})}}}}}}{\sqrt{1 + {2{\mathbb{e}}^{{- 60}{p/{({{TEST}\mspace{14mu}{X/R}})}}}}}} \right\}}} & {{Eq}\mspace{14mu} 14}\end{matrix}$

It can then be determined if the device rating is greater than or equalto I_(adjsym) or I_(adjsymdelay). The pass/fail determinations can thenbe made in steps 1148 and 1150, respectively and the percent rating canbe calculated in step 1152.

If it is determined that the LVCB is fused in step 1122, then the faultX/R can be calculated in step 1126 and compared to the circuit breakertest X/R in order to determine if the calculated fault X/R is greaterthan the circuit breaker test X/R. If it is greater, then I_(adjsym) canbe calculated in step 1154 using the following equation:

$\begin{matrix}{I_{ADJSYM} = {I_{SYM}\left\{ \frac{1.02 + {0.98\mspace{14mu}{\mathbb{e}}^{{- 3}/{({{CALC}\mspace{14mu}{X/R}})}}}}{1.02 + {0.98\mspace{14mu}{\mathbb{e}}^{{- 3}/{({{TEST}\mspace{14mu}{X/R}})}}}} \right\}}} & {{Eq}\mspace{14mu} 13}\end{matrix}$

If the calculated fault X/R is not greater than the circuit breaker testX/R, then I_(adjsym) can be set equal to I_(sym) in step 1156. It canthen be determined if the device rating is greater than or equal toI_(adjsym) in step 1146. The pass/fail determinations can then becarried out in steps 1148 and 1150 respectively, and the percent ratingcan be determined in step 1152.

FIG. 12 is a diagram illustrating an example process for determining theprotective capabilities of a HVCB. In certain embodiments, X/R can becalculated in step 1157 and a peak current (I_(peak)) can be determinedusing equation 11 in step 1158. In step 1162, it can be determinedwhether the HVCB's rating is greater than or equal to I_(peak) asdetermined in step 1158. If the device rating is greater than or equalto I_(peak), then the device has passed in step 1164. Otherwise, thedevice fails in step 1166. In either case, the percent rating can bedetermined in step 1168 using the following:

${\%\mspace{14mu}{rating}} = \frac{I_{PEAK}}{{Device}\mspace{14mu}{rating}}$

In other embodiments, an interrupting time calculation can be made instep 1170. In such embodiments, a fault X/R can be calculated and thencan be determined if the fault X/R is greater than or equal to a circuitbreaker test X/R in step 1172. For example, the following circuitbreaker test X/R can be used;50 Hz Test X/R=13.760 Hz Test X/R=16.7(DC Time contant=0.45 ms)

If the fault X/R is not greater than the circuit breaker test X/R thenI_(adjintsym) can be set equal to I_(sym) in step 1174. If thecalculated fault X/R is greater than the circuit breaker test X/R, thencontact parting time for the circuit breaker can be determined in step1176 and equation 15 can then be used to determine I_(adjintsym) in step1178.

$\begin{matrix}{I_{\underset{SYM}{ADJINT}} = {I_{\underset{SYM}{INT}}\left\{ \frac{\sqrt{1 + {2{\mathbb{e}}^{{- 4}{pf}^{*}{t/{({{CALC}\mspace{14mu}{X/R}})}}}}}}{\sqrt{1 + {2{\mathbb{e}}^{{- 4}{pf}^{*}{t/{({{TEST}\mspace{14mu}{X/R}})}}}}}} \right\}}} & {{Eq}\mspace{14mu} 15}\end{matrix}$

In step 1180, it can be determined whether the device rating is greaterthan or equal to I_(adjintsym). The pass/fail determinations can then bemade in steps 1182 and 1184 respectively and the percent rating can becalculated in step 1186 using the following:

${\%\mspace{14mu}{rating}} = \frac{I_{{ADJINT}\mspace{14mu}{SYM}}}{{Device}\mspace{14mu}{rating}}$

FIG. 13 is a flowchart illustrating an example process for determiningthe protective capabilities of the protective devices being monitored instep 1002 in accordance with another embodiment. The process can startwith a short circuit analysis in step 1302. For systems operating at afrequency other than 60 hz, the protective device X/R can be modified asfollows:(X/R)mod=(X/R)*60H/(system Hz).

For fuses/switches, a selection can be made, as appropriate, between useof the symmetrical rating or asymmetrical rating for the device. TheMultiplying Factor (MF) for the device can then be calculated in step1304. The MF can then be used to determine I_(adjasym) or I_(adjsym). Instep 1306, it can be determined if the device rating is greater than orequal to I_(adjasym) or I_(adjsym). Based on this determination, it canbe determined whether the device passed or failed in steps 1308 and 1310respectively, and the percent rating can be determined in step 1312using the following:% rating=I _(adjasym)*100/device rating; or% rating=I _(adjsym)*100/device rating.

For LVCBs, it can first be determined whether the device is fused instep 1314. If the device is not fused, then in step 1315 it can bedetermined whether the X/R is known for the device. If it is known, thenthe LVF can be calculated for the device in step 1320. It should benoted that the LVF can vary depending on whether the LVCB is aninstantaneous trip device or not. If the X/R is not known, then it canbe determined in step 1317, e.g., using the following:PCB,ICCB=6.59MCCB,ICCB rated<=10,000 A=1.73MCCB,ICCB rated 10,001−20,000 A=3.18MCCB,ICCB rated>20,000 A=4.9

If the device is fused, then in step 1316 it can again be determinedwhether the X/R is known. If it is known, then the LVF can be calculatedin step 1319. If it is not known, then the X/R can be set equal to,e.g., 4.9.

In step 1321, it can be determined if the LVF is less than 1 and if itis, then the LVF can be set equal to 1. In step 1322 I_(intadj) can bedetermined using the following:

-   -   MCCB/ICCB/PCB With Instantaneous:        Iint,adj=LVF*Isym,rms    -   PCB Without Instantaneous:        Iint,adj=LVFp*Isym,rms(½ Cyc)        int,adj=LVFasym*Isym,rms(3-8 Cyc)

In step 1323, it can be determined whether the device's symmetricalrating is greater than or equal to I_(intadj), and it can be determinedbased on this evaluation whether the device passed or failed in steps1324 and 1325 respectively. The percent rating can then be determined instep 1326 using the following:% rating=I _(intadj)*100/device rating.

FIG. 14 is a diagram illustrating a process for evaluating the withstandcapabilities of a MVCB in accordance with one embodiment. In step 1328,a determination can be made as to whether the following calculationswill be based on all remote inputs, all local inputs or on a No AC Decay(NACD) ratio. For certain implementations, a calculation can then bemade of the total remote contribution, total local contribution, totalcontribution (I_(intrmssym)), and NACD. If the calculated NACD is equalto zero, then it can be determined that all contributions are local. IfNACD is equal to 1, then it can be determined that all contributions areremote.

If all the contributions are remote, then in step 1332 the remote MF(MFr) can be calculated and I_(int) can be calculated using thefollowing:I _(int) =MFr*I _(intrmssym)

If all the inputs are local, then MF1 can be calculated and I_(int) canbe calculated using the following:I _(int) =MF1*I _(intrmssym)

If the contributions are from NACD, then the NACD, MFr, MF1, and AMF1can be calculated. If AMF1 is less than 1, then AMF1 can be set equalto 1. I_(int) can then be calculated using the following:I _(int) =AMF1*I _(intrmssym) /S

In step 1338, the 3-phase device duty cycle can be calculated and thenit can be determined in step 1340, whether the device rating is greaterthan or equal to I_(int). Whether the device passed or failed can thenbe determined in steps 1342 and 1344, respectively. The percent ratingcan be determined in step 1346 using the following:% rating=I _(int)*100/3p device rating.

In other embodiments, it can be determined, in step 1348, whether theuser has selected a fixed MF. If so, then in certain embodiments thepeak duty (crest) can be determined in step 1349 and MFp can be setequal to 2.7 in step 1354. If a fixed MF has not been selected, then thepeak duty (crest) can be calculated in step 1350 and MFp can becalculated in step 1358. In step 1362, the MFp can be used to calculatethe following:I _(mompeak) =MFp*I _(symrms)

In step 1366, it can be determined if the device peak rating (crest) isgreater than or equal to I_(mompeak). It can then be determined whetherthe device passed or failed in steps 1368 and 1370 respectively, and thepercent rating can be calculated as follows:% rating=I _(mompeak)*100/device peak(crest)rating.

In other embodiments, if a fixed MF is selected, then a momentary dutycycle (C&L) can be determined in step 1351 and MFm can be set equal to,e.g., 1.6. If a fixed MF has not been selected, then in step 1352 MFmcan be calculated. MFm can then be used to determine the following:I _(momsym) =MFm*I _(symrms)

It can then be determined in step 1374 whether the device C&L, rmsrating is greater than or equal to I_(momsym). Whether the device passedor failed can then be determined in steps 1376 and 1378 respectively,and the percent rating can be calculated as follows:% rating=I _(momasym)*100/device C&L,rms rating.

Thus, the above methods provide a mean to determine the withstandcapability of various protective devices, under various conditions andusing various standards, using an aged, up to date virtual model of thesystem being monitored.

The influx of massive sensory data, e.g., provided via sensors 104, 106,and 108, intelligent filtration of this dense stream of data intomanageable and easily understandable knowledge. For example, asmentioned, it is important to be able to assess the real-time ability ofthe power system to provide sufficient generation to satisfy the systemload requirements and to move the generated energy through the system tothe load points. Conventional systems do not make use of an on-line,real-time system snap shot captured by a real-time data acquisitionplatform to perform real time system availability evaluation.

FIG. 15 is a flow chart illustrating an example process for analyzingthe reliability of an electrical power distribution and transmissionsystem in accordance with one embodiment. First, in step 1502,reliability data can be calculated and/or determined. The inputs used instep 1502 can comprise power flow data, e.g., network connectivity,loads, generations, cables/transformer impedances, etc., which can beobtained from the predicted values generated in step 1008, reliabilitydata associated with each power system component, lists of contingenciesto be considered, which can vary by implementation including by region,site, etc., customer damage (load interruptions) costs, which can alsovary by implementation, and load duration curve information. Otherinputs can include failure rates, repair rates, and requiredavailability of the system and of the various components.

In step 1504 a list of possible outage conditions and contingencies canbe evaluated including loss of utility power supply, generators, UPS,and/or distribution lines and infrastructure. In step 1506, a power flowanalysis for monitored system 102 under the various contingencies can beperformed. This analysis can include the resulting failure rates, repairrates, cost of interruption or downtime versus the required systemavailability, etc. In step 1510, it can be determined if the system isoperating in a deficient state when confronted with a specificcontingency. If it is, then is step 1512, the impact on the system, loadinterruptions, costs, failure duration, system unavailability, etc. canall be evaluated.

After the evaluation of step 1512, or if it is determined that thesystem is not in a deficient state in step 1510, then it can bedetermined if further contingencies need to be evaluated. If so, thenthe process can revert to step 1506 and further contingencies can beevaluated. If no more contingencies are to be evaluated, then a reportcan be generated in step 1514. The report can include a system summary,total and detailed reliability indices, system availability, etc. Thereport can also identify system bottlenecks are potential problem areas.

The reliability indices can be based on the results of credible systemcontingencies involving both generation and transmission outages. Thereliability indices can include load point reliability indices, branchreliability indices, and system reliability indices. For example,various load/bus reliability indices can be determined such asprobability and frequency of failure, expected load curtailed, expectedenergy not supplied, frequency of voltage violations, reactive powerrequired, and expected customer outage cost. The load point indices canbe evaluated for the major load buses in the system and can be used insystem design for comparing alternate system configurations andmodifications.

Overall system reliability indices can include power interruption index,power supply average MW curtailment, power supply disturbance index,power energy curtailment index, severity index, and system availability.For example, the individual load point indices can be aggregated toproduce a set of system indices. These indices are indicators of theoverall adequacy of the composite system to meet the total system loaddemand and energy requirements and can be extremely useful for thesystem planner and management, allowing more informed decisions to bemade both in planning and in managing the system.

The various analysis and techniques can be broadly classified as beingeither Monte Carlo simulation or Contingency Enumeration. The processcan also use AC, DC and fast linear network power flow solutionstechniques and can support multiple contingency modeling, multiple loadlevels, automatic or user-selected contingency enumeration, use avariety of remedial actions, and provides sophisticated reportgeneration.

The analysis of step 1506 can include adequacy analysis of the powersystem being monitored based on a prescribed set of criteria by whichthe system must be judged as being in the success or failed state. Thesystem is considered to be in the failed state if the service at loadbuses is interrupted or its quality becomes unacceptable, i.e., if thereare capacity deficiency, overloads, and/or under/over voltages

Various load models can be used in the process of FIG. 15 includingmulti-step load duration curve, curtailable and Firm, and CustomerOutage Cost models. Additionally, various remedial actions can beproscribed or even initiated including MW and MVAR generation control,generator bus voltage control, phase shifter adjustment, MW generationrescheduling, and load curtailment (interruptible and firm).

In other embodiments, the effect of other variables, such as the weatherand human error can also be evaluated in conjunction with the process ofFIG. 15 and indices can be associated with these factors. For example,FIG. 16 is a flow chart illustrating an example process for analyzingthe reliability of an electrical power distribution and transmissionsystem that takes weather information into account in accordance withone embodiment. Thus, in step 1602, real-time weather data can bereceived, e.g., via a data feed such as an XML feed from NationalOceanic and Atmosphere Administration (NOAA). In step 1604, this datacan be converted into reliability data that can be used in step 1502.

It should also be noted that National Fire Protection Association (NFPA)and the Occupational Safety and Health Association (OSHA) have mandatedthat facilities comply with proper workplace safety standards andconduct Arc Flash studies in order to determine the incident energy,protection boundaries and PPE levels needed to be worn by technicians.Unfortunately, conventional approaches/systems for performing suchstudies do not provide a reliable means for the real-time prediction ofthe potential energy released (in calories per centimeter squared) foran arc flash event. Moreover, no real-time system exists that canpredict the required personal protective equipment (PPE) required tosafely perform repairs as required by NFPA 70E and IEEE 1584.

When a fault in the system being monitored contains an arc, the heatreleased can damage equipment and cause personal injury. It is thelatter concern that brought about the development of the heat exposureprograms referred to above. The power dissipated in the arc radiates tothe surrounding surfaces. The further away from the arc the surface is,the less the energy is received per unit area.

As noted above, conventional approaches are based on highly specializedstatic simulation models that are rigid and non-reflective of thefacilities operational status at the time a technician may be needed toconduct repairs on electrical equipment. But the PPE level required forthe repair, or the safe protection boundary may change based on theactual operational status of the facility and alignment of the powerdistribution system at the time repairs are needed. Therefore, a staticmodel does not provide the real-time analysis that can be critical foraccurate PPE level determination. This is because static systems cannotadjust to the many daily changes to the electrical system that occur ata facility, e.g., motors and pumps may be on or off, on-site generationstatus may have changed by having diesel generators on-line, utilityelectrical feed may also change, etc., nor can they age with thefacility to accurately predict the required PPE levels.

Accordingly, existing systems rely on exhaustive studies to be performedoff-line by a power system engineer or a design professional/specialist.Often the specialist must manually modify a simulation model so that itis reflective of the proposed facility operating condition and thenconduct a static simulation or a series of static simulations in orderto come up with recommended safe working distances, energy calculationsand PPE levels. But such a process is not timely, accurate norefficient, and as noted above can be quite costly.

Using the systems and methods described herein a logical model of afacility electrical system can be integrated into a real-timeenvironment, with a robust AC Arc Flash simulation engine (systemmodeling engine 124), a data acquisition system (data acquisition hub112), and an automatic feedback system (calibration engine 134) thatcontinuously synchronizes and calibrates the logical model to the actualoperational conditions of the electrical system. The ability to re-alignthe simulation model in real-time so that it mirrors the real facilityoperating conditions, coupled with the ability to calibrate and age themodel as the real facility ages, as describe above, provides a desirableapproach to predicting PPE levels, and safe working conditions at theexact time the repairs are intended to be performed. Accordingly,facility management can provide real-time compliance with, e.g., NFPA70E and IEEE 1584 standards and requirements.

FIG. 17 is a diagram illustrating an example process for predicting inreal-time various parameters associated with an alternating current (AC)arc flash incident. These parameters can include for example, the arcflash incident energy, arc flash protection boundary, and requiredPersonal Protective Equipment (PPE) levels, e.g., in order to complywith NFPA-70E and IEEE-1584. First, in step 1702, updated virtual modeldata can be obtained for the system being model, e.g., the updated dataof step 1006, and the operating modes for the system can be determined.In step 1704, an AC 3-phase short circuit analysis can be performed inorder to obtain bolted fault current values for the system. In step1706, e.g., IEEE 1584 equations can be applied to the bolted faultvalues and any corresponding arcing currents can be calculated in step1708.

The ratio of arc current to bolted current can then be used, in step1710, to determine the arcing current in a specific protective device,such as a circuit breaker or fuse. A coordinated time-current curveanalysis can be performed for the protective device in step 1712. Instep 1714, the arcing current in the protective device and the timecurrent analysis can be used to determine an associated fault clearingtime, and in step 1716 a corresponding arc energy can be determinedbased on, e.g., IEEE 1584 equations applied to the fault clearing timeand arcing current.

In step 1718, the 100% arcing current can be calculated and for systemsoperating at less than 1 kV the 85% arcing current can also becalculated. In step 1720, the fault clearing time in the protectivedevice can be determined at the 85% arcing current level. In step 1722,e.g., IEEE 1584 equations can be applied to the fault clearing time(determined in step 1720) and the arcing current to determine the 85%arc energy level, and in step 1724 the 100% arcing current can becompared with the 85% arcing current, with the higher of the two beingselected. IEEE 1584 equations, for example, can then be applied to theselected arcing current in step 1726 and the PPE level and boundarydistance can be determined in step 1728. In step 1730, these values canbe output, e.g., in the form of a display or report.

In other embodiments, using the same or a similar procedure asillustrated in FIG. 17, the following evaluations can be made inreal-time and based on an accurate, e.g., aged, model of the system:

-   -   Arc Flash Exposure based on IEEE 1584;    -   Arc Flash Exposure based on NFPA 70E;    -   Network-Based Arc Flash Exposure on AC Systems/Single Branch        Case;    -   Network-Based Arc Flash Exposure on AC Systems/Multiple Branch        Cases;    -   Network Arc Flash Exposure on DC Networks;    -   Exposure Simulation at Switchgear Box, MCC Box, Open Area and        Cable Grounded and Ungrounded;    -   Calculate and Select Controlling Branch(s) for Simulation of Arc        Flash;    -   Test Selected Clothing;    -   Calculate Clothing Required;    -   Calculate Safe Zone with Regard to User Defined Clothing        Category;    -   Simulated Art Heat Exposure at User Selected locations;    -   User Defined Fault Cycle for 3-Phase and Controlling Branches;    -   User Defined Distance for Subject;    -   100% and 85% Arcing Current;    -   100% and 85% Protective Device Time;    -   Protective Device Setting Impact on Arc Exposure Energy;    -   User Defined Label Sizes;    -   Attach Labels to One-Line Diagram for User Review;    -   Plot Energy for Each Bus;    -   Write Results into Excel;    -   View and Print Graphic Label for User Selected Bus(s); and    -   Work permit.

With the insight gained through the above methods, appropriateprotective measures, clothing and procedures can be mobilized tominimize the potential for injury should an arc flash incident occur.Facility owners and operators can efficiently implement a real-timesafety management system that is in compliance with NFPA 70E and IEEE1584 guidelines.

FIG. 18 is a flow chart illustrating an example process for real-timeanalysis of the operational stability of an electrical powerdistribution and transmission system in accordance with one embodiment.The ability to predict, in real-time, the capability of a power systemto maintain stability and/or recover from various contingency events anddisturbances without violating system operational constraints isimportant. This analysis determines the real-time ability of the powersystem to: 1. sustain power demand and maintain sufficient active andreactive power reserve to cope with ongoing changes in demand and systemdisturbances due to contingencies, 2. operate safely with minimumoperating cost while maintaining an adequate level of reliability, and3. provide an acceptably high level of power quality (maintainingvoltage and frequency within tolerable limits) when operating undercontingency conditions.

In step 1802, the dynamic time domain model data can be updated tore-align the virtual system model in real-time so that it mirrors thereal operating conditions of the facility. The updates to the domainmodel data coupled with the ability to calibrate and age the virtualsystem model of the facility as it ages (i.e., real-time condition ofthe facility), as describe above, provides a desirable approach topredicting the operational stability of the electrical power systemoperating under contingency situations. That is, these updates accountfor the natural aging effects of hardware that comprise the totalelectrical power system by continuously synchronizing and calibratingboth the control logic used in the simulation and the actual operatingconditions of the electrical system

The domain model data includes data that is reflective of both thestatic and non-static (rotating) components of the system. Staticcomponents are those components that are assumed to display no changesduring the time in which the transient contingency event takes place.Typical time frames for disturbance in these types of elements rangefrom a few cycles of the operating frequency of the system up to a fewseconds. Examples of static components in an electrical system includebut are not limited to transformers, cables, overhead lines, reactors,static capacitors, etc. Non-static (rotating) components encompasssynchronous machines including their associated controls (exciters,governors, etc), induction machines, compensators, motor operated valves(MOV), turbines, static var compensators, fault isolation units (FIU),static automatic bus transfer (SABT) units, etc. These various types ofnon-static components can be simulated using various techniques. Forexample:

-   -   a. For Synchronous Machines: thermal (round rotor) and hydraulic        (salient pole) units can be both simulated either by using a        simple model or by the most complete two-axis including damper        winding representation.    -   b. For Induction Machines: a complete two-axis model can be        used. Also it is possible to model them by just providing the        testing curves (current, power factor, and torque as a function        of speed).    -   c. For Motor Operated Valves (MOVs): Two modes of MOV operation        are of interest, namely, opening and closing operating modes.        Each mode of operation consists of five distinct stages, a)        start, b) full speed, c) unseating, d) travel, and e) stall. The        system supports user-defined model types for each of the stages.        That is, “start” may be modeled as a constant current while        “full speed” may be modeled by constant power. This same        flexibility exists for all five distinct stages of the closing        mode.    -   d. For AVR and Excitation Systems: There are a number of models        ranging form rotating (DC and AC) and analogue to static and        digital controls. Additionally, the system offers a user-defined        modeling capability, which can be used to define a new        excitation model.    -   e. For Governors and Turbines: The system is designed to address        current and future technologies including but not limited to        hydraulic, diesel, gas, and combined cycles with mechanical        and/or digital governors.    -   f. For Static Var Compensators (SVCs): The system is designed to        address current and future technologies including a number of        solid-state (thyristor) controlled SVC's or even the saturable        reactor types.    -   g. For Fault Isolation Units (FIUs): The system is designed to        address current and future technologies of FIUs also known as        Current Limiting Devices, are devices installed between the        power source and loads to limit the magnitude of fault currents        that occur within loads connected to the power distribution        networks.    -   h. For Static Automatic Bus Transfers (SABT): The system is        designed to address current and future technologies of SABT        (i.e., solid-state three phase, dual position, three-pole        switch, etc.)

In one embodiment, the time domain model data includes “built-in”dynamic model data for exciters, governors, transformers, relays,breakers, motors, and power system stabilizers (PSS) offered by avariety of manufactures. For example, dynamic model data for theelectrical power system may be OEM manufacturer supplied control logicfor electrical equipment such as automatic voltage regulators (AVR),governors, under load tap changing transformers, relays, breakersmotors, etc. In another embodiment, in order to cope with recentadvances in power electronic and digital controllers, the time domainmodel data includes “user-defined” dynamic modeling data that is createdby an authorized system administrator in accordance with user-definedcontrol logic models. The user-defined models interacts with the virtualsystem model of the electrical power system through “InterfaceVariables” 1816 that are created out of the user-defined control logicmodels. For example, to build a user-defined excitation model, thecontrols requires that generator terminal voltage to be measured andcompared with a reference quantity (voltage set point). Based on thespecific control logic of the excitation and AVR, the model would thencompute the predicted generator field voltage and return that value backto the application. The user-defined modeling supports a large number ofpre-defined control blocks (functions) that are used to assemble therequired control systems and put them into action in a real-timeenvironment for assessing the strength and security of the power system.In still another embodiment, the time domain model data includes bothbuilt-in dynamic model data and user-defined model data.

Moving on to step 1804, a contingency event can be chosen out of adiverse list of contingency events to be evaluated. That is, theoperational stability of the electrical power system can be assessedunder a number of different contingency event scenarios including butnot limited to a singular event contingency or multiple eventcontingencies (that are simultaneous or sequenced in time). In oneembodiment, the contingency events assessed are manually chosen by asystem administrator in accordance with user requirements. In anotherembodiment, the contingency events assessed are automatically chosen inaccordance with control logic that is dynamically adaptive to pastobservations of the electrical power system. That is the control logic“learns” which contingency events to simulate based on past observationsof the electrical power system operating under various conditions.

Some examples of contingency events include but are not limited to:

-   -   Application/removal of three-phase fault.    -   Application/removal of phase-to-ground fault    -   Application/removal of phase-phase-ground fault.    -   Application/removal of phase-phase fault.    -   Branch Addition.    -   Branch Tripping    -   Starting Induction Motor.    -   Stopping Induction Motor    -   Shunt Tripping.    -   Shunt Addition (Capacitor and/or Induction)    -   Generator Tripping.    -   SVC Tripping.    -   Impact Loading (Load Changing Mechanical Torque on Induction        Machine. With this option it is actually possible to turn an        induction motor to an induction generator)    -   Loss of Utility Power Supply/Generators/UPS/Distribution        Lines/System Infrastructure    -   Load Shedding

In step 1806, a transient stability analysis of the electrical powersystem operating under the various chosen contingencies can beperformed. This analysis can include identification of system weaknessesand insecure contingency conditions. That is, the analysis can predict(forecast) the system's ability to sustain power demand, maintainsufficient active and reactive power reserve, operate safely withminimum operating cost while maintaining an adequate level ofreliability, and provide an acceptably high level of power quality whilebeing subjected to various contingency events. The results of theanalysis can be stored by an associative memory engine 1818 during step1814 to support incremental learning about the operationalcharacteristics of the system. That is, the results of the predictions,analysis, and real-time data may be fed, as needed, into the associativememory engine 1818 for pattern and sequence recognition in order tolearn about the logical realities of the power system. In certainembodiments, engine 1818 can also act as a pattern recognition engine ora Hierarchical Temporal Memory (HTM) engine. Additionally, concurrentinputs of various electrical, environmental, mechanical, and othersensory data can be used to learn about and determine normality andabnormality of business and plant operations to provide a means ofunderstanding failure modes and give recommendations.

In step 1810, it can be determined if the system is operating in adeficient state when confronted with a specific contingency. If it is,then in step 1812, a report is generated providing a summary of theoperational stability of the system. The summary may include generalpredictions about the total security and stability of the system and/ordetailed predictions about each component that makes up the system.

Alternatively, if it is determined that the system is not in a deficientstate in step 1810, then step 1808 can determine if furthercontingencies needs to be evaluated. If so, then the process can revertto step 1806 and further contingencies can be evaluated.

The results of real-time simulations performed in accordance with FIG.18 can be communicated in step 1812 via a report, such as a print out ordisplay of the status. In addition, the information can be reported viaa graphical user interface (thick or thin client) that illustrated thevarious components of the system in graphical format. In suchembodiments, the report can simply comprise a graphical indication ofthe security or insecurity of a component, subsystem, or system,including the whole facility. The results can also be forwarded toassociative memory engine 1818, where they can be stored and madeavailable for predictions, pattern/sequence recognition and ability toimagine, e.g., via memory agents or other techniques, some of which aredescribe below, in step 1820.

The process of FIG. 18 can be applied to a number of needs including butnot limited to predicting system stability due to: Motor starting andmotor sequencing, an example is the assessment of adequacy of a powersystem in emergency start up of auxiliaries; evaluation of theprotections such as under frequency and under-voltage load sheddingschemes, example of this is allocation of required load shedding for apotential loss of a power generation source; determination of criticalclearing time of circuit breakers to maintain stability; anddetermination of the sequence of protective device operations andinteractions.

FIG. 19 is a flow chart illustrating an example process for conducting areal-time power capacity assessment of an electrical power distributionand transmission system, in accordance with one embodiment. Thestability of an electrical power system can be classified into two broadcategories: transient (angular) stability and voltage stability (i.e.,power capacity). Voltage stability refers to the electrical system'sability to maintain acceptable voltage profiles under different systemtopologies and load changes (i.e., contingency events). That is, voltagestability analyses determine bus voltage profiles and power flows in theelectrical system before, during, and immediately after a majordisturbance. Generally speaking, voltage instability stems from theattempt of load dynamics to restore power consumption beyond thecapability of the combined transmission and generation system. Onefactor that comes into play is that unlike active power, reactive powercannot be transported over long distances. As such, a power system richin reactive power resources is less likely to experience voltagestability problems. Overall, the voltage stability of a power system isof paramount importance in the planning and daily operation of anelectrical system.

Traditionally, transient stability has been the main focus of powersystem professionals. However, with the increased demand for electricalenergy and the regulatory hurdles blocking the expansion of existingpower systems, the occurrences of voltage instability has becomeincreasingly frequent and therefore has gained increased attention frompower system planners and power system facility operators. The abilityto learn, understand and make predictions about available power systemcapacity and system susceptibility to voltage instability, in real-timewould be beneficial in generating power trends for forecasting purposes.

In step 1902, the voltage stability modeling data for the componentscomprising the electrical system can be updated to re-align the virtualsystem model in “real-time” so that it mirrors the real operatingconditions of the facility. These updates to the voltage stabilitymodeling data coupled with the ability to calibrate and age the virtualsystem model of the facility as it ages (i.e., real-time condition ofthe facility), as describe above, provides a desirable approach topredicting occurrences of voltage instability (or power capacity) in theelectrical power system when operating under contingency situations.That is, these updates account for the natural aging effects of hardwarethat comprise the total electrical power system by continuouslysynchronizing and calibrating both the control logic used in thesimulation and the actual operating conditions of the electrical system

The voltage stability modeling data includes system data that has directinfluence on the electrical system's ability to maintain acceptablevoltage profiles when the system is subjected to various contingencies,such as when system topology changes or when the system encounters powerload changes. Some examples of voltage stability modeling data are loadscaling data, generation scaling data, load growth factor data, loadgrowth increment data, etc.

In one embodiment, the voltage stability modeling data includes“built-in” data supplied by an OEM manufacturer of the components thatcomprise the electrical equipment. In another embodiment, in order tocope with recent advances power system controls, the voltage stabilitydata includes “user-defined” data that is created by an authorizedsystem administrator in accordance with user-defined control logicmodels. The user-defined models interact with the virtual system modelof the electrical power system through “Interface Variables” 1916 thatare created out of the user-defined control logic models. In stillanother embodiment, the voltage stability modeling data includes acombination of both built-in model data and user-defined model data

Moving on to step 1904, a contingency event can be chosen out of adiverse list of contingency events to be evaluated. That is, the voltagestability of the electrical power system can be assessed under a numberof different contingency event scenarios including but not limited to asingular event contingency or multiple event contingencies (that aresimultaneous or sequenced in time). In one embodiment, the contingencyevents assessed are manually chosen by a system administrator inaccordance with user requirements. In another embodiment, thecontingency events assessed are automatically chosen in accordance withcontrol logic that is dynamically adaptive to past observations of theelectrical power system. That is the control logic “learns” whichcontingency events to simulate based on past observations of theelectrical power system operating under various conditions. Someexamples of contingency events include but are not limited to: loss ofutility supply to the electrical system, loss of available powergeneration sources, system load changes/fluctuations, loss ofdistribution infrastructure associated with the electrical system, etc.

In step 1906, a voltage stability analysis of the electrical powersystem operating under the various chosen contingencies can beperformed. This analysis can include a prediction (forecast) of thetotal system power capacity, available system power capacity andutilized system power capacity of the electrical system of theelectrical system under various contingencies. That is, the analysis canpredict (forecast) the electrical system's ability to maintainacceptable voltage profiles during load changes and when the overallsystem topology undergoes changes. The results of the analysis can bestored by an associative memory engine 1918 during step 1914 to supportincremental learning about the power capacity characteristics of thesystem. That is, the results of the predictions, analysis, and real-timedata may be fed, as needed, into the associative memory engine 1918 forpattern and sequence recognition in order to learn about the voltagestability of the electrical system in step 1920. Additionally,concurrent inputs of various electrical, environmental, mechanical, andother sensory data can be used to learn about and determine normalityand abnormality of business and plant operations to provide a means ofunderstanding failure modes and give recommendations.

In step 1910, it can be determined if there is voltage instability inthe system when confronted with a specific contingency. If it is, thenin step 1912, a report is generated providing a summary of the specificsand source of the voltage instability. The summary may include generalpredictions about the voltage stability of the overall system and/ordetailed predictions about each component that makes up the system.

Alternatively, if it is determined that the system is not in a deficientstate in step 1910, then step 1908 can determine if furthercontingencies needs to be evaluated. If so, then the process can revertto step 1906 and further contingencies can be evaluated.

The results of real-time simulations performed in accordance with FIG.19 can be communicated in step 1912 via a report, such as a print out ordisplay of the status. In addition, the information can be reported viaa graphical user interface (thick or thin client) that illustrated thevarious components of the system in graphical format. In suchembodiments, the report can simply comprise a graphical indication ofthe capacity of a subsystem or system, including the whole facility. Theresults can also be forwarded to associative memory engine 1918, wherethey can be stored and made available for predictions, pattern/sequencerecognition and ability to imagine, e.g., via memory agents or othertechniques, some of which are describe below, in step 1920

The systems and methods described above can also be used to providereports (step 1912) on, e.g., total system electrical capacity, totalsystem capacity remaining, total capacity at all busbars and/orprocesses, total capacity remaining at all busbars and/or processes,total system loading, loading at each busbar and/or process, etc.

Thus, the process of FIG. 19 can receive input data related to powerflow, e.g., network connectivity, loads, generations,cables/transformers, impedances, etc., power security, contingencies,and capacity assessment model data and can produce as outputs datarelated to the predicted and designed total system capacity, availablecapacity, and present capacity. This information can be used to makemore informed decisions with respect to management of the facility.

FIG. 20 is a flow chart illustrating an example process for performingreal-time harmonics analysis of an electrical power distribution andtransmission system, in accordance with one embodiment. As technologicaladvances continue to be made in the field of electronic devices, therehas been particular emphasis on the development of energy savingfeatures. Electricity is now used quite differently from the way it usedbe used with new generations of computers and peripherals using verylarge-scale integrated circuitry operating at low voltages and currents.Typically, in these devices, the incoming alternating current (AC)voltage is diode rectified and then used to charge a large capacitor.The electronic device then draws direct current (DC) from the capacitorin short non-linear pulses to power its internal circuitry. Thissometimes causes harmonic distortions to arise in the load current,which may result in overheated transformers and neutrals, as well astripped circuit breakers in the electrical system.

The inherent risks (to safety and the operational life of componentscomprising the electrical system) that harmonic distortions poses toelectrical systems have led to the inclusion of harmonic distortionanalysis as part of traditional power analysis. Metering and sensorpackages are currently available to monitor harmonic distortions withinan electrical system. However, it is not feasible to fully sensor out anelectrical system at all possible locations due to cost and the physicalaccessibility limitations in certain parts of the system. Therefore,there is a need for techniques that predict, through real-timesimulation, the sources of harmonic distortions within an electricalsystem, the impacts that harmonic distortions have or may have, and whatsteps (i.e., harmonics filtering) may be taken to minimize or eliminateharmonics from the system.

Currently, there are no reliable techniques for predicting, inreal-time, the potential for periodic non-sinusoidal waveforms (i.e.harmonic distortions) to occur at any location within an electricalsystem powered with sinusoidal voltage. In addition, existing techniquesdo not take into consideration the operating conditions and topology ofthe electrical system or utilizes a virtual system model of the systemthat “ages” with the actual facility or its current condition. Moreover,no existing technique combines real-time power quality meter readingsand predicted power quality readings for use with a pattern recognitionsystem such as an associative memory machine learning system to predictharmonic distortions in a system due to changes in topology or pooroperational conditions within an electrical system.

The process, described herein, provides a harmonics analysis solutionthat uses a real-time snap shot captured by a data acquisition system toperform a real-time system power quality evaluation at all locationsregardless of power quality metering density. This process integrates,in real-time, a logical simulation model (i.e., virtual system model) ofthe electrical system, a data acquisition system, and power systemsimulation engines with a logic based approach to synchronize thelogical simulation model with conditions at the real electrical systemto effectively “age” the simulation model along with the actualelectrical system. Through this approach, predictions about harmonicdistortions in an electrical system may be accurately calculated inreal-time. Condensed, this process works by simulating harmonicdistortions in an electrical system through subjecting a real-timeupdated virtual system model of the system to one or more simulatedcontingency situations.

In step 2002, the harmonic frequency modeling data for the componentscomprising the electrical system can be updated to re-align the virtualsystem model in “real-time” so that it mirrors the real operatingconditions of the facility. These updates to the harmonic frequencymodeling data coupled with the ability to calibrate and age the virtualsystem model of the facility as it ages (i.e., real-time condition ofthe facility), as describe above, provides a desirable approach topredicting occurrences of harmonic distortions within the electricalpower system when operating under contingency situations. That is, theseupdates account for the natural aging effects of hardware that comprisethe total electrical power system by continuously synchronizing andcalibrating both the control logic used in the simulation and the actualoperating conditions of the electrical system.

Harmonic frequency modeling data has direct influence over how harmonicdistortions are simulated during a harmonics analysis. Examples of datathat is included with the harmonic frequency modeling data include: IEEE519 and/or Mil 1399 compliant system simulation data,generator/cable/motor skin effect data, transformer phase shifting data,generator impedance data, induction motor impedance data, etc.

Moving on to step 2004, a contingency event can be chosen out of adiverse list of contingency events to be evaluated. That is, theelectrical system can be assessed for harmonic distortions under anumber of different contingency event scenarios including but notlimited to a singular event contingency or multiple event contingencies(that are simultaneous or sequenced in time). In one embodiment, thecontingency events assessed are manually chosen by a systemadministrator in accordance with user requirements. In anotherembodiment, the contingency events assessed are automatically chosen inaccordance with control logic that is dynamically adaptive to pastobservations of the electrical power system. That is the control logic“learns” which contingency events to simulate based on past observationsof the electrical power system operating under various conditions. Someexamples of contingency events include but are not limited to additions(bringing online) and changes of equipment that effectuate a non-linearload on an electrical power system (e.g., as rectifiers, arc furnaces,AC/DC drives, variable frequency drives, diode-capacitor input powersupplies, uninterruptible power supplies, etc.) or other equipment thatdraws power in short intermittent pulses from the electrical powersystem.

Continuing with FIG. 20, in step 2006, a harmonic distortion analysis ofthe electrical power system operating under the various chosencontingencies can be performed. This analysis can include predictions(forecasts) of different types of harmonic distortion data at variouspoints within the system. Harmonic distortion data may include but arenot limited to:

-   -   Wave-shape Distortions/Oscillations data    -   Parallel and Series Resonant Condition data    -   Total Harmonic Distortion Level data (both Voltage and Current        type)    -   Data on the true RMS system loading of lines, transformers,        capacitors, etc.    -   Data on the Negative Sequence Harmonics being absorbed by the AC        motors    -   Transformer K-Factor Level data    -   Frequency scan at positive, negative, and zero angle response        throughout the entire scanned spectrum in the electrical system.

That is, the harmonics analysis can predict (forecast) variousindicators (harmonics data) of harmonic distortions occurring within theelectrical system as it is being subjected to various contingencysituations. The results of the analysis can be stored by an associativememory engine 2016 during step 2014 to support incremental learningabout the harmonic distortion characteristics of the system. That is,the results of the predictions, analysis, and real-time data may be fed,as needed, into the associative memory engine 2016 for pattern andsequence recognition in order to learn about the harmonic distortionprofile of the electrical system in step 2018. Additionally, concurrentinputs of various electrical, environmental, mechanical, and othersensory data can be used to learn about and determine normality andabnormality of business and plant operations to provide a means ofunderstanding failure modes and give recommendations.

In step 2010, it can be determined if there are harmonic distortionswithin the system when confronted with a specific contingency. If it is,then in step 2012, a report is generated providing a summary ofspecifics regarding the characteristics and sources of the harmonicdistortions. The summary may include forecasts about the different typesof harmonic distortion data (e.g., Wave-shape Distortions/Oscillationsdata, Parallel and Series Resonant Condition data, etc.) generated atvarious points throughout the system. Additionally, through theseforecasts, the associative memory engine 2016 can make predictions aboutthe natural oscillation response(s) of the facility and compare thosepredictions with the harmonic components of the non-linear loads thatare fed or will be fed from the system as indicated form the dataacquisition system and power quality meters. This will give anindication of what harmonic frequencies that the potential resonantconditions lie at and provide facility operators with the ability toeffectively employ a variety of harmonic mitigation techniques (e.g.,addition of harmonic filter banks, etc.)

Alternatively, if it is determined that the system is not in a deficientstate in step 2010, then step 2008 can determine if furthercontingencies needs to be evaluated. If so, then the process can revertto step 2006 and further contingencies can be evaluated.

The results of real-time simulations performed in accordance with FIG.20 can be communicated in step 2012 via a report, such as a print out ordisplay of the status. In addition, the information can be reported viaa graphical user interface (thick or thin client) that illustrated thevarious components of the system in graphical format. In suchembodiments, the report can simply comprise a graphical indication ofthe harmonic status of subsystem or system, including the wholefacility. The results can also be forwarded to associative memory engine2016, where they can be stored and made available for predictions,pattern/sequence recognition and ability to imagine, e.g., via memoryagents or other techniques, some of which are describe below, in step2018

Thus, the process of FIG. 20 can receive input data related to powerflow, e.g., network connectivity, loads, generations,cables/transformers, impedances, etc., power security, contingencies,and can produce as outputs data related to Point Specific Power QualityIndices, Branch Total Current Harmonic Distortion Indices, Bus and NodeTotal Voltage Harmonic Distortion Indices, Frequency Scan Indices forPositive Negative and Zero Sequences, Filter(s) Frequency AngleResponse, Filter(s) Frequency Impedance Response, and Voltage andCurrent values over each filter elements (r, xl, xc).

FIG. 21 is a diagram illustrating how the HTM Pattern Recognition andMachine Learning Engine works in conjunction with the other elements ofthe analytics system to make predictions about the operational aspectsof a monitored system, in accordance with one embodiment. As depictedherein, the HTM Pattern Recognition and Machine Learning Engine 551 ishoused within an analytics server 116 and communicatively connected viaa network connection 114 with a data acquisition hub 112, a clientterminal 128 and a virtual system model database 526. The virtual systemmodel database 526 is configured to store the virtual system model ofthe monitored system. The virtual system model is constantly updatedwith real-time data from the data acquisition hub 112 to effectivelyaccount for the natural aging effects of the hardware that comprise thetotal monitored system, thus, mirroring the real operating conditions ofthe system. This provides a desirable approach to predicting theoperational aspects of the monitored power system operating undercontingency situations.

The HTM Machine Learning Engine 551 is configured to store and processpatterns observed from real-time data fed from the hub 112 and predicteddata output from a real-time virtual system model of the monitoredsystem. These patterns can later be used by the HTM Engine 551 to makereal-time predictions (forecasts) about the various operational aspectsof the system.

The data acquisition hub 112 is communicatively connected via dataconnections 110 to a plurality of sensors that are embedded throughout amonitored system 102. The data acquisition hub 112 may be a standaloneunit or integrated within the analytics server 116 and can be embodiedas a piece of hardware, software, or some combination thereof. In oneembodiment, the data connections 110 are “hard wired” physical dataconnections (e.g., serial, network, etc.). For example, a serial orparallel cable connection between the sensors and the hub 112. Inanother embodiment, the data connections 110 are wireless dataconnections. For example, a radio frequency (RF), BLUETOOTH™, infraredor equivalent connection between the sensor and the hub 112.

Examples of a monitored system includes machinery, factories, electricalsystems, processing plants, devices, chemical processes, biologicalsystems, data centers, aircraft carriers, and the like. It should beunderstood that the monitored system can be any combination ofcomponents whose operations can be monitored with conventional sensorsand where each component interacts with or is related to at least oneother component within the combination.

Continuing with FIG. 21, the client 128 is typically a conventional“thin-client” or “thick client” computing device that may utilize avariety of network interfaces (e.g., web browser, CITRIX™, WINDOWSTERMINAL SERVICES™, telnet, or other equivalent thin-client terminalapplications, etc.) to access, configure, and modify the sensors (e.g.,configuration files, etc.), power analytics engine (e.g., configurationfiles, analytics logic, etc.), calibration parameters (e.g.,configuration files, calibration parameters, etc.), virtual systemmodeling engine (e.g., configuration files, simulation parameters, etc.)and virtual system model of the system under management (e.g., virtualsystem model operating parameters and configuration files).Correspondingly, in one embodiment, the data from the various componentsof the monitored system and the real-time predictions (forecasts) aboutthe various operational aspects of the system can be displayed on aclient 128 display panel for viewing by a system administrator orequivalent. In another embodiment, the data may be summarized in a hardcopy report 2102.

As discussed above, the HTM Machine Learning Engine 551 is configured towork in conjunction with a real-time updated virtual system model of themonitored system to make predictions (forecasts) about certainoperational aspects of the monitored system when it is subjected to acontingency event. For example, where the monitored system is anelectrical power system, in one embodiment, the HTM Machine LearningEngine 551 can be used to make predictions about the operationalreliability of an electrical power system in response to contingencyevents such as a loss of power to the system, loss of distributionlines, damage to system infrastructure, changes in weather conditions,etc. Examples of indicators of operational reliability include but arenot limited to failure rates, repair rates, and required availability ofthe power system and of the various components that make up the system.

In another embodiment, the operational aspects relate to an arc flashdischarge contingency event that occurs during the operation of thepower system. Examples of arc flash related operational aspects includebut are not limited to quantity of energy released by the arc flashevent, required personal protective equipment (PPE) for personneloperating within the confines of the system during the arc flash event,and measurements of the arc flash safety boundary area around componentscomprising the power system. In still another embodiment, theoperational aspect relates to the operational stability of the systemduring a contingency event. That is, the system's ability to sustainpower demand, maintain sufficient active and reactive power reserve,operate safely with minimum operating cost while maintaining an adequatelevel of reliability, and provide an acceptably high level of powerquality while being subjected to a contingency event.

In still another embodiment, the operational aspect relates to thevoltage stability of the electrical system immediately after beingsubjected to a major disturbance (i.e., contingency event). Generallyspeaking, voltage instability stems from the attempt of load dynamics torestore power consumption, after the disturbance, in a manner that isbeyond the capability of the combined transmission and generationsystem. Examples of predicted operational aspects that are indicative ofthe voltage stability of an electrical system subjected to a disturbanceinclude the total system power capacity, available system power capacityand utilized system power capacity of the electrical system under beingsubjected to various contingencies. Simply, voltage stability is theability of the system to maintain acceptable voltage profiles whileunder the influence of the disturbances.

In still yet another embodiment, the operational aspect relates toharmonic distortions in the electrical system subjected to a majordisturbance. Harmonic distortions are characterized by non-sinusoidal(non-linear) voltage and current waveforms. Most harmonic distortionsresult from the generation of harmonic currents caused by nonlinear loadsignatures. A nonlinear load is characteristic in products such ascomputers, printers, lighting and motor controllers, and much of today'ssolid-state equipment. With the advent of power semiconductors and theuse of switching power supplies, the harmonics distortion problem hasbecome more severe.

Examples of operational aspects that are indicative of harmonicdistortions include but are not limited to: wave-shapedistortions/oscillations, parallel and series resonance, total harmonicdistortion level, transformer K-Factor levels, true RMS loading oflines/transformers/capacitors, indicators of negative sequence harmonicsbeing absorbed by alternating current (AC) motors,positive/negative/zero angle frequency response, etc.

FIG. 22 is an illustration of the various cognitive layers that comprisethe neocortical catalyst process used by the HTM Pattern Recognition andMachine Learning Engine to analyze and make predictions about theoperational aspects of a monitored system, in accordance with oneembodiment. As depicted herein, the neocortical catalyst process isexecuted by a neocortical model 2202 that is encapsulated by a real-timesensory system layer 2204, which is itself encapsulated by anassociative memory model layer 2206. Each layer is essential to theoperation of the neocortical catalyst process but the key component isstill the neocortical model 2202. The neocortical model 2202 representsthe “ideal” state and performance of the monitored system and it iscontinually updated in real-time by the sensor layer 2204. The sensorylayer 2204 is essentially a data acquisition system comprised of aplurality of sensors imbedded within the electrical system andconfigured to provide real-time data feedback to the neocortical model2202. The associative memory layer observes the interactions between theneocortical model 2202 and the real-time sensory inputs from the sensorylayer 2204 to learn and understand complex relationships inherent withinthe monitored system. As the neocortical model 2202 matures over time,the neocortical catalyst process becomes increasingly accurate in makingpredictions about the operational aspects of the monitored system. Thiscombination of the neocortical model 2202, sensory layer 2204 andassociative memory model layer 2206 works together to learn, refine,suggest and predict similarly to how the human neocortex operates.

FIG. 23 is an example process for real-time three-dimensional (3D)visualization of the health, reliability, and performance of anelectrical system, in accordance with one embodiment. The complexity ofelectrical power systems coupled with the many operational conditionsthe systems can be asked to operate under pose significant challenges toowners, operators and managers of critical electrical networks. It isvital for owners and operators alike to have a precise and wellunderstood perspective of the overall health and performance of theelectrical network. Communication of such status throughthree-dimensional (3D) visualization views (such as 3D Plant LifecycleModels), in addition to the traditional two-dimensional (2D) views,greatly enhances the ability of operators, owners and executives tounderstand the health and predicted performance of their power networks,elegantly and efficiently.

In step 2302, the power analytics server can determine which operatingmode(s) that the electrical system is being simulated under. That is,the virtual system model of the electrical system can be modified by theuser to simulate the system operating under multiple different operatingscenarios (conditions) and system contingencies. The power analyticsserver is configured to utilize the operating mode settings whilesimulating the operation of the electrical system to make predictionsabout the system's health, performance, availability and reliability. Inone embodiment, the operating mode(s) relate to the multiple contingencyevents that the electrical system may be subjected to during regularoperations. The contingency events can be chosen out of a diverse listof contingency events to be evaluated. That is, the operational health,performance, availability and reliability of the electrical power systemcan be assessed under a number of different contingency event scenariosincluding but not limited to a singular event contingency or multipleevent contingencies (that are simultaneous or sequenced in time). Thatis, in one embodiment, the contingency events assessed are manuallychosen by a user in accordance with the his/her requirements. In anotherembodiment, the contingency events assessed are automatically chosen inaccordance with control logic that is dynamically adaptive to pastobservations of the electrical power system. That is the control logic“learns” which contingency events to simulate based on past observationsof the electrical power system operating under various conditions.

Some examples of contingency events include but are not limited to:

-   -   Application/removal of three-phase fault    -   Application/removal of phase-to-ground fault    -   Application/removal of phase-phase-ground fault    -   Application/removal of phase-phase fault    -   Branch Addition    -   Branch Tripping    -   Starting Induction Motor    -   Stopping Induction Motor    -   Shunt Tripping    -   Shunt Addition (Capacitor and/or Induction)    -   Generator Tripping    -   SVC Tripping    -   Impact Loading (Load Changing Mechanical Torque on Induction        Machine.    -   With this option it is actually possible to turn an induction        motor to an induction generator)    -   Loss of Utility Power Supply/Generators/UPS/Distribution        Lines/System Infrastructure    -   Load Shedding

In another embodiment, the operating mode(s) can relate to the multipleload levels that the electrical system operates under. That is, thevirtual system model of the electrical system can be simulated undervarious power system load configurations or capacity conditions. In oneembodiment, the system is simulated as operating under a base load powerconfiguration. That is, the electrical system can be simulated asoperating continuously at its maximum rated power output. Under thisconfiguration, power systems only shut down to perform maintenance or ifsomething breaks. Accordingly, the ability to test under such conditionscannot be achieved in conventional systems. In another embodiment, theelectrical system can be simulated as operating under a load followingpower configuration. That is, the electrical system is simulated asoperating in a fluctuating manner by adjusting its power output asdemand for electricity fluctuates throughout the day. In still anotherembodiment, the electrical system is simulated as operating at variousdifferent power load capacity levels. For example, the electrical systemmay be simulated as operating at 10%, 25%, 50%, 75%, or 100% of itsrated power generation capacity.

Continuing with FIG. 23, the operating mode(s) can relate to differentsystem and load point reliability indices assigned to the componentsthat make up the electrical system. In one embodiment, for example,changes can be made to the reliability indices of individual components.In another embodiment, changes can be made to all the components thatmake up the system.

In still yet another embodiment, the operating mode(s) relate to thedifferent remedial measures or actions that are implemented on theelectrical system to respond to the various contingency situations thatthe system may be subjected to. For example, remedial measures canrelate to: the various types of uninterruptible power supply (UPS)systems operating on the electrical system, various protective devicesthat are integrated to the system, various operating limits andconditions that are placed on the system, etc.

In step 2304, the power analytics server is configured to utilize theoperating mode settings, determined in step 2302, and the updatedvirtual system model of the electrical system to simulate and predictaspects relating to the real-time health, performance, reliability andavailability of the electrical system. For example, the power analyticsserver can simulate and predict aspects relating to:

-   -   Power System Health and Performance    -   Variations or deviations of electrical system performance from        the power system design parameters. That is, the ability of the        electrical system to resist system output variations or        deviations from defined tolerance limits of the electrical        system    -   Incorporation of performance and behavioral specifications for        all the equipment and components that comprise the electrical        system into a real-time management environment    -   System Reliability and Availability    -   As a function of different system, process and load point        reliability indices    -   Implementation of different technological solutions to achieve        reliability centered maintenance targets and goals    -   Power System Capacity Levels    -   As-designed total power capacity of the power system.    -   How much of the total power capacity remains or is available        (ability of the electrical system to maintain availability of        its total power capacity)    -   Present utilized power capacity.    -   Power System Strength and Resilience    -   Dynamic stability predictions across all contingency events    -   Determination of protection system stress and withstand status

Additionally, the predictions may also relate to the real-time abilityof the electrical system to: 1. sustain power demand and maintainsufficient active and reactive power reserve to cope with ongoingchanges in demand and system disturbances due to contingencies, 2.operate safely with minimum operating cost while maintaining an adequatelevel of reliability, and 3. provide an acceptably high level of powerquality (maintaining voltage and frequency within tolerable limits) whenoperating under contingency conditions.

Continuing with FIG. 23, in step 2306, the power analytics server isconfigured to output the predictions in the form of a print out ordisplay of text, graphics, charts, labels, and model views that readilycommunicates the health and predicted performance of the electricalsystem in an elegant and efficient fashion. The information can bereported via a graphical user interface (“thick” or “thin” client) thatillustrates the various components of the system in graphical format. Insuch embodiments, the report can simply comprise a graphical indicationof the capacity of a subsystem or system, including the whole facility.The results can also be forwarded to associative memory engine 2308,where they can be stored and made available for predictions,pattern/sequence recognition and ability to imagine, e.g., via memoryagents or other techniques, some of which are describe below, in step2308.

In one embodiment, the model views are 3D (i.e., 3D Plant LifecycleModel) model views of the various components, equipment and sub-systemsthat comprise the electrical system. Examples of some 3D model views2502 are depicted in a client interface screenshot in FIG. 25. The 3Dmodel views 2502, can be generated by an integrated 3D visualizationengine that is an integrated part of the power analytics server. Inanother embodiment, the model views are 2D model views of the variouscomponents, equipment and sub-systems making up the electrical system.An example of a 2D model view 2504 is also depicted in FIG. 25.

As alluded to above, in step 2308, the results of the simulation andpredictive analysis can be stored by an associative memory engine tosupport incremental learning about the power capacity characteristics ofthe system. That is, the results of the predictions, analysis, andreal-time data may be fed, as needed, into an machine learning enginefor pattern and sequence recognition in order to learn about the health,performance, reliability and availability of the electrical system.Additionally, concurrent inputs of various electrical, environmental,mechanical, and other sensory data can be used to learn about anddetermine normality and abnormality of business and plant operations toprovide a means of understanding failure modes and generaterecommendations.

FIG. 24 is a diagram illustrating how the 3D Visualization Engine worksin conjunction with the other elements of the analytics system toprovide 3D visualization of the health, reliability, and performance ofan electrical system, in accordance with one embodiment. As depictedherein, the 3D Visualization Engine 2402 is integrated within a poweranalytics server 116 that is communicatively connected via a networkconnection 114 with a data acquisition hub 112, a client terminal 128and a virtual system model database 526. The virtual system modeldatabase 526 is configured to store the virtual system model of theelectrical system. The virtual system model is constantly updated withreal-time data from the data acquisition hub 112 to effectively accountfor the natural aging effects of the hardware that comprise the totalelectrical power system, thus, mirroring the real operating conditionsof the system. This provides a desirable approach to predicting theoperational aspects of the monitored power system and for communicatingthe predicted aspects through 3D visualization models of the facility.

The 3D visualization engine 2402 is interfaced with the predictiveelements of the power analytics server and communicatively connected tothe data acquisition hub 112 and the client 128. The data acquisitionhub 112 is communicatively connected via data connections 110 to aplurality of sensors that are embedded throughout the electrical system102. The data acquisition hub 112 may be a standalone unit or integratedwithin the analytics server 116 and can be embodied as a piece ofhardware, software, or some combination thereof. In one embodiment, thedata connections 110 are “hard wired” physical data connections (e.g.,serial, network, etc.). For example, a serial or parallel cableconnection between the sensors and the hub 112. In another embodiment,the data connections 110 are wireless data connections. For example, aradio frequency (RF), BLUETOOTH™, infrared or equivalent connectionbetween the sensor and the hub 112. Real-time system data readings canbe fed continuously to the data acquisition hub 112 from the varioussensors that are embedded within the electrical system 102.

Continuing with FIG. 24, the client 128 is typically a conventionalthin-client or thick-client computing device that may utilize a varietyof network interfaces (e.g., web browser, CITRIX™, WINDOWS TERMINALSERVICES™, telnet, or other equivalent thin-client terminalapplications, etc.) to access, configure, and modify the sensors (e.g.,configuration files, etc.), analytics engine (e.g., configuration files,analytics logic, etc.), calibration parameters (e.g., configurationfiles, calibration parameters, etc.), virtual system modeling engine(e.g., configuration files, simulation parameters, choice of contingencyevent to simulate, etc.), 3D visualization engine (e.g., configurationfiles, 3D visualization parameters, etc.) and virtual system model ofthe system under management (e.g., virtual system model operatingparameters and configuration files). Correspondingly, in one embodiment,the data from the various components of the electrical system and thereal-time predictions (forecasts) about the health, performance,reliability and availability of the electrical system can be displayedon a client 128 display panel for viewing by a system administrator orequivalent. In another embodiment, the data may be summarized in a hardcopy report 2404.

FIG. 26 is a diagram illustrating how the Schematic User InterfaceCreator Engine works in conjunction with the other elements of theanalytics system to automatically generate a schematic user interfacefor visualizing the health, reliability, and performance of anelectrical system, in accordance with one embodiment. Conventionalelectrical power system monitoring technologies typically rely on customgraphical design and user-interface development efforts in order tocreate a system schematic user interface (displayable on a clientterminal) that can be linked to real-time sensory data output by thevarious components that comprise an electrical power system. In general,custom development efforts tend to be cumbersome and often require anextraordinarily amount of time to implement.

Given the complexity of modern electrical power systems and thesignificant challenges they pose to owners, operators and managers ofcritical (regional, national and international) electrical networks;there is a need for automated software tools that can allow the rapiddeployment of schematic based user interfaces to provide precise andwell understood perspective of the overall health and performance of thevarious components that comprise an electrical power system. Ideally,the tools can be configured to automatically read electrical systemconfiguration data from a database containing a virtual systemrepresentation (i.e., virtual system model) of the electrical system,generate a schematic user interface view of the electrical system, andintelligently link the various components included in the user interfaceto the predicted, monitored and/or derived output/values of thosevarious components.

As depicted herein, the Schematic User Interface Creator Engine 2602 canbe integrated within a power analytics server 116 that can becommunicatively connected via a network connection 114 with a dataacquisition hub 112, a client terminal 128 and a virtual system modeldatabase 526. The virtual system model database 526 can be configured tostore the virtual system model of the electrical system. The virtualsystem model can be constantly updated with real-time data from the dataacquisition hub 112 to effectively account for the natural aging effectsof the hardware that comprise the total electrical power system, thus,mirroring the real operating conditions of the system. The SchematicUser Interface Creator Engine 2602 can be configured to automaticallycreate a schematic user interface that is representative of theelectrical system and link that interface to the sensors monitoring thecomponents (i.e., electrical equipment) that comprise the electricalsystem to enable real-time monitoring of the derived output/values fromthose components. The user interface can include a visual representationof each piece of electrical equipment (associated/tagged with a uniqueidentifier) that comprises the electrical system. In one embodiment, theschematic user interface is based on a one-line diagram construct. Inanother embodiment, the schematic user interface is based on a technicalsystem schematic diagram construct. However, it should be appreciatedthat the user interface can be based on any engineering diagramconstruct as long as the resulting interface can be displayed on aclient terminal 128 to allow viewing by an operator/administrator.

In addition to being communicatively connected to the data acquisitionhub 112 and the client 128, the Schematic User Interface Creator Engine2602 can also be interfaced with the predictive elements of the poweranalytics server. The predictive elements of the power analytics servermay relate to the real-time health, performance, reliability andavailability of the electrical system. For example, the predictions canbe indicative of the real-time ability of the electrical system to: 1.sustain power demand and maintain sufficient active and reactive powerreserve to cope with ongoing changes in demand and system disturbancesdue to contingencies, 2. operate safely with minimum operating costwhile maintaining an adequate level of reliability, and 3. provide anacceptably high level of power quality (maintaining voltage andfrequency within tolerable limits) when operating under contingencyconditions.

The data acquisition hub 112 can be communicatively connected via dataconnections 110 to a plurality of sensors that can be embeddedthroughout the electrical system 102. The data acquisition hub 112 canbe a standalone unit or integrated within the analytics server 116 andcan be embodied as a piece of hardware, software, or some combinationthereof. In one embodiment, the data connections 110 are “hard wired”physical data connections (e.g., serial, network, etc.). For example, aserial or parallel cable connection between the sensors and the hub 112.In another embodiment, the data connections 110 are wireless dataconnections. For example, a radio frequency (RF), BLUETOOTH™, infraredor equivalent connection between the sensor and the hub 112. Real-timesystem data readings can be fed continuously to the data acquisition hub112 from the various sensors that are embedded within the electricalsystem 102.

Continuing with FIG. 26, the client 128 can be a conventionalthin-client or thick-client computing device that can utilize a varietyof network interfaces (e.g., web browser, CITRIX™, WINDOWS TERMINALSERVICES™, telnet, or other equivalent thin-client terminalapplications, etc.) to access, configure, and modify the sensors (e.g.,configuration files, etc.), power analytics engine (e.g., configurationfiles, analytics logic, etc.), calibration parameters (e.g.,configuration files, calibration parameters, etc.), virtual systemmodeling engine (e.g., configuration files, simulation parameters,choice of contingency event to simulate, etc.), Schematic User InterfaceCreator Engine 2602 (e.g., configuration files, schematic interfacealgorithms, etc.) and virtual system model of the electrical systemunder management (e.g., virtual system model operating parameters andconfiguration files). Correspondingly, in one embodiment, the real-timedata from the various monitored components of the electrical system andthe real-time predictions (forecasts) about the health, performance,reliability and availability of the electrical system can besimultaneously visualized on the schematic user interface that isdisplayed on a client terminal 128 for viewing by a system administratoror equivalent. This schematic user interface can provide a desirableapproach to communicating the monitored and predicted operationalaspects of an electrical system to an operator/administrator. In oneembodiment, the schematic user interface is rendered in a 2-dimensional(2D) graphical image format. In another embodiment, the schematic userinterface is rendered in a 3-dimensional (3D) graphical image format.

FIG. 27 is an example process for automatically generating a schematicuser interface for visualizing the health, reliability, and performanceof an electrical system, in accordance with one embodiment. In oneembodiment, the operational steps that comprise the process areimplemented through a schematic user interface creator engine(application/software tool) that runs on the power analytics server. Inanother embodiment, the operational steps that comprise the process areimplemented through a schematic interface creator engine that runs on aseparate (network application) server that is communicatively connectedto the power analytics server. In still another embodiment, theoperational steps that comprise the process are implemented through aplurality of discrete applications that are distributed amongst one ormore (network application) servers that are communicatively connectedwith the power analytics server. It should be understood, however, thatthe application(s) can be distributed in any configuration as long asthe application(s) can communicatively access the power analytics serverto implement the process.

The process begins with step 2702, where system configuration data canbe extracted from a virtual system model of the electrical system. Thevirtual system model can be stored in one or more virtual system modeldatabase(s) that are communicatively connected to the power analyticsserver. The configuration data can be stored in the memory of the poweranalytics server (or a network application server) and can include theunique identifiers (i.e., node IDs) of each of the components (i.e.,piece of electrical equipment) that comprise the virtual system model,connectivity information (i.e., the electrical connectivity between thevarious virtual system model components and/or the data connectivitywith the sensors monitoring those components) and/or equipment specificinformation such as bus or branch specific equipment type (e.g.,generator, circuit breaker, transformer, motor, fuse, static load,etc.).

In step 2704, a logical construct of the virtual system model can beconstructed from the system configuration data. In one embodiment, thelogical construct can be created in an Extensible Markup Language (XML)format. In another embodiment, the logical construct can be created inan Extensible HyperText Markup Language (XHTML) format. It should beappreciated that the logical construct can be created using any mark-uplanguage as long as it can be utilized to convey system configurationinformation about the components (i.e., electrical equipment) that makeup the virtual system model.

In step 2706, one or more graphical objects can be generated torepresent one or more pieces of electrical equipment included in thelogical construct. This can be accomplished through the schematic userinterface creator engine or equivalent application(s) parsing the systemconfiguration data stored in the logical construct and generatingappropriate symbol block(s) and/or graphical object(s) for each piece ofelectrical equipment that comprise the electrical system. The symbolblock(s) or graphical object(s) that are generated can then beindividually organized as buses and/or branches.

In step 2708, the one or more graphical objects can be organized togenerate a schematic user interface layout of the electrical system.This can be accomplished using a self-executing algorithm that can beeither an integrated component of the schematic user interface creatorengine or a separate discrete application that is configured to work inconjunction with the schematic user interface creator engine. In oneembodiment, the self-executing algorithm is a .NET based application. Inanother embodiment, the self-executing algorithm is an ACTIVE X basedapplication. In still another embodiment, the self-executing algorithmis a JAVA based application. It should be understood, however, that theself-executing algorithm can be created using any type of programminglanguage as long as the resulting algorithm can function either as acomponent of the schematic user interface creator engine or inconjunction with the same.

In one embodiment, the self-executing algorithm is in a force directedlayout format. In another embodiment, the self-executing algorithm is ina tree layout format. In still another embodiment, the self-executingalgorithm is in a layered diagraph layout format. It should beappreciated that the self-executing algorithm can follow any format aslong as each of the one or more graphical objects/symbol blocks in theresulting schematic user interface layout can later be linked to acorresponding piece of electrical equipment that comprise the electricalsystem.

After the schematic user interface layout of the electrical system isgenerated, it can be further optimized using the schematic interfacecreator engine (or equivalent application) to scan the schematic userinterface layout and re-align the graphical object(s) based on one ormore user selected optimization criteria.

In step 2710, each of the one or more graphical objects in the schematicuser interface layout can be communicatively linked to sensorsconfigured to monitor the real-time operational status of the one ormore pieces of electrical equipment represented by the one or moregraphical objects. This can be accomplished by intelligently linking theunique identifiers (e.g., equipment IDs) associated with each of thegraphical objects/symbol blocks to their corresponding database filesand creating a tag or communication channel with the same uniqueidentifier to allow the files to be populated with data from theelectrical equipment associated with each unique identifier. Forexample, a Graphical Object A with a unique identifier of “001” can belinked to the database file “A” which is associated with the “001”identifier. A communication channel “001” can then be opened to allowdata, acquired from a piece of electrical equipment associated with the“001” identifier, to populate database file “A.”

The communication linkage between the graphical objects in the schematicuser interface layout and the database(s) that store real-time dataacquired from the operation of the electrical equipment allow theschematic user interface to dynamically represent fluctuations in thereal-time health, performance, reliability and availability of theelectrical system. For example, the buses and branches in the schematicuser interface layout can be configured so that they change colorsand/or become animated in response to the monitored real-time data ofand/or predicted values for the electrical system during operation.

FIG. 28 is a diagram illustrating how the Energy Management SystemEngine works in conjunction with the other elements of the analyticssystem to intelligently monitor and manage the cost, quality andreliability of energy generated and/or utilized by an electrical system,in accordance with one embodiment. Conventional approaches to energymanagement typically rely on real-time data readings supplied directlyfrom power quality meters and sensors that are interfaced with thecomponents (that comprise an electrical system) to provide a simple livemetrics (e.g., voltage, current, frequency, etc.) of how the electricalsystem is operating. Alternatively, conventional energy managementsystems may also permit basic historical trending and rudimentarystatistical methods to be performed to generate a historical energyprofile of how the electrical system has previously operated.

That is, a conventional energy management system only presents a user(i.e., electrical system owner, administrator, and/or operator) with aview of how the electrical system is currently operating and/or hasoperated in the past without having the ability to make predictionsabout how the electrical system will operate in the future or allow therunning of simulations based on user programmed “what-if” scenarios. Theability to predict the active power demand, system losses, reactivepower demand and other energy parameters via a model (i.e., virtualsystem model) of the electrical system that can age and synchronizeitself in real-time with the electrical system's actual operatingconditions is critical in obtaining accurate predictions of the system'senergy efficiency (i.e., cost of losses that are inherent to theelectrical system and those due to the inefficient operation of theelectrical system), energy costs, reliability, availability, health andperformance. Without operational conditions synchronization or an agingability, these predictions are of little value as they are notreflective of the actual facility status and may lead the user to makefalse conclusions.

Given the attendant challenges that modern electrical power systems poseto owners, operators and managers of critical (facility specific,regional, national and international) electrical networks and theshortcomings of conventional energy management systems; there is a needfor an energy management system that integrates a real-time energy costcomputational algorithm (i.e., real-time utility power pricing engine)along with a logical power flow, forecasting, state estimation,reliability and availability model (i.e., virtual system model) of theelectrical system, a data acquisition system, and power systemsimulation engines with a logic based approach to the adjustment of keyparameters within the virtual system model to synchronize the virtualsystem model with the real facility and effectively “age” the virtualsystem model along with the electrical system it is associated with.Such a system can be configured to make predictions regarding theexpected energy efficiency, energy costs, cost of inherent system lossesand cost due to running the electrical system at poor power factorsalong with calculating and comparing the availability and reliability ofthe electrical system in real-time. These predictions and calculationscan then be used to arrive at actionable, reliability centeredmaintenance and energy management strategies for mission critical orbusiness critical operations which may lead to the re-alignment of theelectrical system for optimized performance, maintenance or security.

As depicted herein, the Energy Management System Engine 2802 can beintegrated within a power analytics server 116 that can becommunicatively connected via a network connection 114 with a dataacquisition hub 112, a client terminal 128 and a virtual system modeldatabase 526. The virtual system model database 526 can be configured tostore the virtual system model of the electrical system 102. The virtualsystem model can be constantly updated with real-time data from the dataacquisition hub 112 to effectively account for the natural aging effectsof the hardware that comprise the total electrical power system, thus,mirroring the real operating conditions of the system.

In addition to being communicatively connected to the data acquisitionhub 112 and the client 128, the Energy Management System Engine 2802 canalso be interfaced with the predictive elements of the power analyticsserver. The predictive elements of the power analytics server 116 mayrelate to the real-time health, performance, efficiency, reliability andavailability of the electrical system 102. For example, the predictionscan be indicative of the real-time ability of the electrical system 102to: 1. sustain power demand and maintain sufficient active and reactivepower reserve to cope with ongoing changes in demand and systemdisturbances due to contingencies, 2. operate safely with minimumoperating cost while maintaining an adequate level of reliability, and3. provide an acceptably high level of power quality (maintainingvoltage and frequency within tolerable limits) when operating undercontingency conditions.

The Energy Management System Engine 2802 can be configured to processthe real-time data output, the predicted data output, historical dataoutput and forecasted aspects about the operation of the electricalsystem 102 to generate a user interface that can convey an operationalstate of the electrical system 102 to a user (i.e., electrical system102 owner/system administrator/operator). In one embodiment, theoperational state can be the real-time operational performance of theelectrical system 102. In another embodiment, the operational state canbe the predicted operational performance of the electrical system 102.In still another embodiment, the operational state can be a historicaldata trending display of the historical operational performance of theelectrical system 102.

For example, the Energy Management System Engine 2802 can be configuredto generate a text-based or a graphics-based user interface that conveysreal-time, predicted and/or historical operational performance of theelectrical system 102 that can include real-time, predicted orhistorical information regarding the electrical system's 102 energyefficiency (i.e., the cost of energy utilized by the electrical system102, the cost of intrinsic power losses within the electrical system102, the cost of power losses due to the electrical system 102 runningat poor power factors), reliability (i.e., the predicted ability of theelectrical system 102 to withstand a contingency event that results instress to the electrical system 102), availability (e.g., the predictedability of the electrical system 102 to maintain availability of totalpower capacity), health and performance. Moreover, the user interfacecan also include a visual representation of each piece of electricalequipment (associated/tagged with a unique identifier) that comprisesthe electrical system 102. In one embodiment, the user interface isbased on a one-line diagram construct. In another embodiment, the userinterface is based on a technical system schematic diagram construct.However, it should be appreciated that the user interface can be basedon any engineering diagram construct as long as the resulting interfacecan be displayed on a client terminal 128 to allow viewing by anoperator/administrator.

The data acquisition hub 112 can be communicatively connected via dataconnections 110 to a plurality of sensors that can be embeddedthroughout the electrical system 102. The data acquisition hub 112 canbe a standalone unit or integrated within the analytics server 116 andcan be embodied as a piece of hardware, software, or some combinationthereof. In one embodiment, the data connections 110 are “hard wired”physical data connections (e.g., serial, network, etc.). For example, aserial or parallel cable connection between the sensors and the hub 112.In another embodiment, the data connections 110 are wireless dataconnections. For example, a radio frequency (RF), BLUETOOTH™, infraredor equivalent connection between the sensor and the hub 112. Real-timesystem data readings can be fed continuously to the data acquisition hub112 from the various sensors that are embedded within the electricalsystem 102.

Continuing with FIG. 28, the client 128 can be a conventionalthin-client or thick-client computing device that can utilize a varietyof network interfaces (e.g., web browser, CITRIX™, WINDOWS TERMINALSERVICES™, telnet, or other equivalent thin-client terminalapplications, etc.) to access, configure, and modify the sensors (e.g.,configuration files, etc.), power analytics engine (e.g., configurationfiles, analytics logic, etc.), calibration parameters (e.g.,configuration files, calibration parameters, etc.), virtual systemmodeling engine (e.g., configuration files, simulation parameters,choice of contingency event to simulate, etc.), Energy Management SystemEngine 2802 (e.g., configuration files, etc.) and virtual system modelof the electrical system 102 under management (e.g., virtual systemmodel operating parameters and configuration files). Correspondingly, inone embodiment, the real-time data from the various monitored componentsof the electrical system 102 and the real-time predictions (forecasts)about the health, performance, reliability and availability of theelectrical system 102 can be simultaneously visualized on the userinterface that is displayed on a client 128 terminal for viewing by asystem administrator or equivalent. This user interface can provide adesirable approach to communicating the monitored and predictedoperational aspects of an electrical system 102 to anoperator/administrator. In one embodiment, the user interface isrendered in a 2-dimensional (2D) graphical image format. In anotherembodiment, the user interface is rendered in a 3-dimensional (3D)graphical image format.

FIG. 29 is a logic flow diagram depicting how the various elements ofthe Energy Management System can interact to provide intelligent energymonitoring and management of an electrical system, in accordance withone embodiment. As depicted, the Energy Management System can include apower analytics server 116 that can be communicatively connected to areal-time historical data trending database 2902, a virtual system modeldatabase 526, a data acquisition component 112 and a conventional webbrowser 2904. The data acquisition component 112 can be configured tocommunicate “real-time”sensor data readings 2906 from the varioussensors interfaced throughout the electrical system to the analyticsserver 116.

In one embodiment, the connection is a “hardwire” physical connection.For example, the power analytics server 116 can be communicativelyconnected (via Category 5 (CAT5), fiber optic or equivalent cabling) tothe data acquisition component 112. In another embodiment, theconnection is a wireless connection (e.g., Wi-Fi, BLUETOOTH, etc.). Forexample, a wireless connection utilizing an 802.11b/g or equivalenttransmission format. In still another embodiment, the connection can bea combination of “hardwire” and “wireless” connection elements that arelinked together based on the particular requirements of the EnergyManagement System.

Still with FIG. 29, the power analytics server 116 can be configured tohost one or more analytic engines that allow the Energy ManagementSystem to perform its various functions. For example, as depicted hereinFIG. 29, the power analytics server 116 can host a machine learningengine 2908, a virtual system modeling engine 2922 and/or a utilitypower pricing engine 2914. The machine learning engine 2908 can beconfigured to work in conjunction with the virtual system modelingengine 2922 and a virtual system model of the electrical system to makereal-time predictions (i.e., forecasts) about the various operationalaspects of the electrical system. The machine learning engine 2908 workby processing and storing patterns observed during the normal operationof the electrical system over time. These observations are provided inthe form of real-time data captured using a multitude of sensors thatare imbedded within the electrical system.

The utility pricing engine 2914 can be configured to access a utilitypower pricing data source 2916 (that includes energy cost tables andother power billing data) to generate real-time energy cost and usagedata 2910 that is reflective of the operational efficiency andperformance of the electrical system. Examples of real-time energy costand usage data 2910 can include, but are not limited to: 1. thereal-time cost of energy utilized by the electrical system (energycost), 2. the real-time cost of intrinsic power losses within theelectrical system (cost of losses), and/or 3. the real-time cost ofpower losses due to the electrical system running at poor power factors(cost due to poor power factor).

In one embodiment, the utility power pricing data source 2916 ispopulated with static utility power pricing data 2918. That is, utilitypower pricing data that is either directly supplied by a user of theEnergy Management System or data that is extracted from utility datapricing data sheets/tables that are downloaded from the utility powerprovider supplying electrical power to the electrical system. In anotherembodiment, the utility power pricing data source 2916 is populated withreal-time dynamic power pricing data 2920 directly from the utilitypower provider supplying the electrical power to the electrical system.For example, the real-time dynamic power pricing data 2920 can be powerspot pricing that is set by a utility power provider based on a varietyof different real-time power grid operational factors (e.g., power gridload, cost of power generation, etc.).

Continuing with FIG. 29, the virtual system model database 526 can beconfigured to store a virtual system model of the electrical system. Thevirtual system model can be constantly updated with real-time data fromthe data acquisition hub 112 to effectively account for the naturalaging effects of the hardware that comprise the total electrical powersystem, thus, mirroring the real operating conditions of the system.Moreover, the virtual system model stored in the virtual system modeldatabase 526 can be accessed by the power analytic engines (i.e.,machine learning engine 2908 and virtual system modeling engine 2922)that are part of the Energy Management System to make various types ofpower analytics forecasts/predictions including, but not limited to:power system reliability predictions 2928, power system operationsforecasts 2926, power system state estimations 2924 and/or power systemoperational cost predictions (i.e., cost of energy, cost of losses andcost associated with running the electrical system inefficiently).

The real-time historical data trending database 2902 can be configuredto store the real-time data output, the predicted data output and theforecasted aspects output from the power analytics server 116 and applya historical trending algorithm to generate a historical data trendingdisplay that is indicative of the historical performance of theelectrical system. The historical data trending display can present manydifferent categories of data relating to the historical operation of theelectrical system, including but not limited to:

Active Power (kW)

Reactive Power (kVAR)

Power Factor (%)

Humidity (%)

Temperature (OF)

Total Cost of Energy ($)

Total Penalty Cost Due to Poor Power Factor ($)

Frequency (Hz)

Voltage (p.u.)

Cost of Losses ($)

In one embodiment, the network connection 114 is a “hardwired” physicalconnection. For example, the data acquisition hub 112 may becommunicatively connected (via Category 5 (CAT5), fiber optic orequivalent cabling) to a data server (not shown) that is communicativelyconnected (via CAT5, fiber optic or equivalent cabling) through theInternet and to the analytics server 116 server. The analytics server116 being also communicatively connected with the Internet (via CAT5,fiber optic, or equivalent cabling). In another embodiment, the networkconnection 114 is a wireless network connection (e.g., Wi-Fi, WLAN,etc.). For example, utilizing an 802.11b/g or equivalent transmissionformat. In practice, the network connection utilized is dependent uponthe particular requirements of the monitored system 102.

The energy management system engine, hosted by the power analyticsserver 116, can be configured to collect and process the real-time dataoutput, the predicted data output and the forecasted aspects output fromthe various analytic engines (i.e., a machine learning engine 2908, avirtual system modeling engine 2922 and/or a utility power pricingengine 2914) that comprise the Energy Management System and generate atext or graphical user interface that conveys an operational state ofthe electrical system.

The embodiments described herein, can be practiced with other computersystem configurations including hand-held devices, microprocessorsystems, microprocessor-based or programmable consumer electronics,minicomputers, mainframe computers and the like. The embodiments canalso be practiced in distributing computing environments where tasks areperformed by remote processing devices that are linked through anetwork.

It should also be understood that the embodiments described herein canemploy various computer-implemented operations involving data stored incomputer systems. These operations are those requiring physicalmanipulation of physical quantities. Usually, though not necessarily,these quantities take the form of electrical or magnetic signals capableof being stored, transferred, combined, compared, and otherwisemanipulated. Further, the manipulations performed are often referred toin terms, such as producing, identifying, determining, or comparing.

Any of the operations that form part of the embodiments described hereinare useful machine operations. The invention also relates to a device oran apparatus for performing these operations. The systems and methodsdescribed herein can be specially constructed for the required purposes,such as the carrier network discussed above, or it may be a generalpurpose computer selectively activated or configured by a computerprogram stored in the computer. In particular, various general purposemachines may be used with computer programs written in accordance withthe teachings herein, or it may be more convenient to construct a morespecialized apparatus to perform the required operations.

Certain embodiments can also be embodied as computer readable code on acomputer readable medium. The computer readable medium is any datastorage device that can store data, which can thereafter be read by acomputer system. Examples of the computer readable medium include harddrives, network attached storage (NAS), read-only memory, random-accessmemory, CD-ROMs, CD-Rs, CD-RWs, magnetic tapes, and other optical andnon-optical data storage devices. The computer readable medium can alsobe distributed over a network coupled computer systems so that thecomputer readable code is stored and executed in a distributed fashion.

Conventional approaches to energy monitoring and management typicallyrely on real-time data readings supplied directly from power qualitymeters and sensors that are interfaced with the components (thatcomprise an electrical system) to provide a simple live metrics (e.g.,voltage, current, frequency, etc.) of how the electrical system isoperating. Furthermore, conventional simulation technologies are PC orthick client applications that require the installation and managementof desktop software in order to operate. Existing solutions do not takeadvantage of the next generation Web 2.0 workplace and fail to deliver aset of rich power system design, analysis Internet applications (RIAs)which can substantially improve the way power system engineers can e.g.create and access content, complete sizing and calculations, and producereports.

FIG. 30 is a diagram illustrating how the various elements of theClient/Server system can interact to provide intelligent energymonitoring and management of an electrical system, in accordance withone embodiment. According to one embodiment herein, a true client/serverapplication framework can combine a rich user interface capability ofdesktop power system engineering client software with the universallyaccessible, no-download features of web-delivered applications.Accordingly, web-delivered applications can deliver a true thin clientsystem for such tasks as e.g. power system design, analysis, sizingcalculations, and reporting applications. This method is an idealsolution for addressing the need for an outstanding user experience thatempowers power system engineers and design specialists to accessapplications via an all-in-one seamless, personalized, and highly visualengineering design and information workplace based on a RIA technologysuch as, for instance, AJAX™, FLASH™, DHTML, and others.

According to one embodiment herein, a system may consist of both aserver-side component and client-side components and communicate via aweb application server. For instance the server side system can beimplemented as a Java Servlet that can run in any Java servlet container(e.g. a J2EE servlet container or a similar JAVA VIRTUAL MACHINE™technology). The web application server can communicate with the energymonitoring infrastructure and deliver derived content to the clientterminal (e.g. via servlets) related to, e.g., the virtual systemmodeling, system analytics, schematics, reports, or user management.

As depicted herein, the web application server 3002 can becommunicatively connected via a network connection 114 with a dataacquisition hub 112, and a client terminal 128. The data acquisition hub112 can be communicatively connected via data connections 110 to aplurality of sensors that can be embedded throughout the electricalsystem 102. The data acquisition hub 112 can be a standalone unit orintegrated within the web application server 3140 and can be embodied asa piece of hardware, software, or some combination thereof. In oneembodiment, the data connections 110 can be “hard wired” physical dataconnections (e.g., serial, network, etc.). For example, a serial orparallel cable connection between the sensors and the hub 112. Inanother embodiment, the data connections 110 are wireless dataconnections. For example, a radio frequency (RF), BLUETOOTH™, infraredor equivalent connection between the sensor and the hub 112. Real-timesystem data readings can be fed continuously to the data acquisition hub112 from the various sensors that are embedded within the electricalsystem 102.

The client 128 can be a conventional thin-client or thick-clientcomputing device that can utilize a variety of network interfaces (e.g.,web browser, CITRIX™, WINDOWS TERMINAL SERVICES™, telnet, or otherequivalent thin-client terminal applications, etc.) to access,configure, and modify the sensors (e.g., configuration files, etc.),power analytics engine (e.g., configuration files, analytics logic,etc.), calibration parameters (e.g., configuration files, calibrationparameters, etc.), virtual system modeling engine (e.g., configurationfiles, simulation parameters, choice of contingency event to simulate,etc.), power analytics engine(s) (e.g., configuration files, etc.) andvirtual system model of the electrical system 102 under management(e.g., virtual system model operating parameters and configurationfiles). Correspondingly, in one embodiment, the real-time data from thevarious monitored components of the electrical system 102 and thereal-time predictions (forecasts) about the health, performance,reliability and availability of the electrical system 102 can besimultaneously visualized on the user interface that is displayed on aclient 128 terminal for viewing by a system administrator or equivalent.This user interface can provide a desirable approach to communicatingthe monitored and predicted operational aspects of an electrical system102 to an operator/administrator. In one embodiment, the user interfaceis rendered in a 2-dimensional (2D) graphical image format. In anotherembodiment, the user interface is rendered in a 3-dimensional (3D)graphical image format.

The virtual system model can be constantly updated with real-time datafrom the data acquisition hub 112 to effectively account for the naturalaging effects of the hardware that comprise the total electrical powersystem, thus, mirroring the real operating conditions of the system.

FIG. 31 is a diagram illustrating various elements of the webapplication server illustrated in FIG. 30, in accordance with oneembodiment. In one embodiment, the web application server 3002 cancomprise a virtual system model database 526, a power analyticsimulation engine 3110, and an analytics services engine 3140. The poweranalytic simulation engine 3110 can comprise a virtual system modelingengine 124 (as previously described). Optionally, the power analyticsimulation engine 3110 can also comprise a number of other engines asdescribed above, for instance, an energy management system engine 2802,a schematic user interface creator engine 2602, a HTM PatternRecognition and Machine Learning Engine 551, a reporting engine 3114, oran equipment library editor engine 3112. The power analytic simulationengine 3110 may also include other engines described above which arecommunicatively connected to the virtual system model database 526.

A virtual system model database 526 can be communicatively connected tothe data acquisition component, such as a data acquisition hub 112, andcan be configured, for instance, to store a virtual system model of theelectrical system. A virtual system modeling engine 526 can beconfigured to generate a predicted data output for the electrical systemutilizing the virtual system model of the electrical system. Ananalytics engine 3140 can be communicatively connected to the virtualsystem model database, and can be configured to monitor the real-timedata output and the predicted data output of the electrical system 102,and to initiate a calibration and synchronization operation to updatethe virtual system model when a difference between the real-time dataoutput and the predicted data output exceeds a threshold.

According to one embodiment described herein, the virtual systemmodeling engine 124 may be provided via a graphical and/or text baseddata entry and layout interface. This engine can support modeling ofelectrical power system networks such as AC (e.g., 3phase, 1phase, and3phase/1phase mixed networks) and DC systems or AC/DC mixed networks.Additionally, it can support control system modeling and analysis fortime domain simulation models or it can support grounding, cable sizing,and other power system modeling activities as needed. The model databasesolution and function set can capture and store not only the networktopography but also connectivity, interdependencies, costs, partnumbers, weight, physical dimensions along with the mechanical,electrical, and other physics based characteristics of the equipmentwithin the electrical network. The database shall also support featuressuch as revision control, revision history, tracking, trending androll-back features along with Save, Save-As, import and export of data,drawings and other input sources. The database can also contain businesslogic to expedite the modeling process.

The equipment library editor engine 3112 can communicate with anequipment library database 3134 to provide a library of equipment,operating characteristics (e.g. electrical characteristics, mechanicalcharacteristics, etc.). The equipment library editor engine 3112, can beused to add, edit, or delete database records within the equipmentlibrary database 3134. Furthermore, the equipment library editor engine3112 can allow users to create and interact with their own customlibrary of equipment or to a global library which is used by all users.

The analytics services engine 3140 in various embodiments, can beconfigured to perform functions and extract data from the virtual systemmodel database 526. In one embodiment, the analytics services engine3140 can perform requested simulations, reporting, and analysis via anappropriate graphical/textual/audio format as appropriate. The analyticsservices engine 3140, can be used to input data and check connectivityerrors. It can also be used for short circuit and fault analysisanalytics (IEEE/ANSI/IEC and similar) for AC and DC systems. Theanalytics services engine 3140 can provide Power Flow Simulation andvoltage control features including load analysis for AC and DC systems.The analytics services engine can be configured to provide protectivedevice coordination and automatic selection expert system typetechnologies for AC and DC systems.

The analytics services engine 3140 can also be configured to provide arcflash simulation and reporting for AC and DC systems per latest NFPA andIEEE standards such as NFPA 70E and IEEE 1584 for example. Additionally,the analytics services engine 3140 can be configured to performtransient stability simulation and reporting. The analytics servicesengine 3140 can be configured to perform power quality analysis andharmonic simulations and mitigation including automatic filter sizingfor complex power systems, including phase dependant networks. Theanalytics services engine 3140 can also be configured to provideprotective device evaluation for electrical power systems.

The power analytics engine 3110 can also provide reporting functionalityvia a reporting engine 3114. The reporting engine 3114 can communicateto the virtual system model database 526 and/or a reporting database inorder to generate a display for reports, permit saving, printing,formatting, and exporting reports. For instance, the reports can includeinput data reports, error checking reports, etc., and can be generatedin a graphical format, a textual format, or a combination of graphicaland textual format.

Additionally, the server side may include customer interface engines3102, such as a customer management engine 3106 or an e-commerce engine3104. In addition to the virtual system model database 526, according toone embodiment herein, the web application server may also comprise orbe in communication with additional databases 3130 as needed. Forinstance, database(s) for users rights management to store electricalon-line diagram models, schematics, reports or other features.

For example, according to one embodiment, an e-commerce engine 3104 canbe configured to communicate with a billing database 3132 to provide ane-commerce component which can be configured to manage use payments andtransactions.

In another embodiment, a customer management engine 3106 can beconfigured to communicate with a customer database 3136 to provide ancustomer management component which can be configured to manage customeraccounts records, end user rights, and user access levels.

In additional embodiments, support components can be added to the webapplication server. These components can include an engine component ora database component as needed. For example, a support component can beadded along with on-line reference libraries and tutorials. These can bestored in various mediums for example as rich multimedia files,interactive references, or standard print materials stored in anelectronic format (such as a PDF).

Thus, in the various embodiments the web application server is able totransform the way electrical power system design and simulationapplications work together on the Web and enables delivery of powersystem engineering applications that combine the rich user interfacecapabilities of desktop client software with the universally accessible,no-down features of web-delivered applications.

FIG. 32 is a logic flow diagram depicting how the various elements ofthe Client/Server system can interact to provide intelligent energymonitoring and management of an electrical system, in accordance withone embodiment. According to one embodiment, a method for interactingwith an electrical system management application to perform poweranalytic analysis simulations on a virtual system model of theelectrical power system, can comprise: in step 3202, a web applicationserver, receiving a user request to access the electrical managementsystem from a client terminal, and in step 3204, sending a userinterface for interaction with the electrical management system to aclient terminal; in step 3206, the client terminal, receiving the userinterface for interaction with the electrical management system, and instep 3208, sending user interaction data to the electrical systemmanagement application; and in step 3210, the electrical systemmanagement application, performing analytic analysis on a virtual systemmodel of the electrical power system.

Additionally, in one embodiment described herein, a method forinteracting with an electrical system management application to performpower analytic analysis simulations on a virtual system model of theelectrical power system can further comprise: the web applicationserver, communicating the user interaction data to a virtual systemmodel engine; the virtual system model engine, accessing a virtualsystem model of the electrical system stored in a virtual system modeldatabase, generating a predicted data output for the electrical systemutilizing the virtual system model of the electrical system, andcommunicating the generated predicted data to the web applicationserver.

Furthermore, in one embodiment described herein, a method forinteracting with an electrical system management application to performpower analytic analysis simulations on a virtual system model of theelectrical power system can further comprise: the web applicationserver, communicating the user interaction data to an analytics engine;and the analytics engine, monitoring the real-time data output and thepredicted data output of the electrical system stored in a virtualsystem model database, and initiating a calibration and synchronizationoperation to update the virtual system model when a difference betweenthe real-time data output and the predicted data output exceeds athreshold.

Any of the operations that form part of the embodiments described hereinare useful machine operations. The invention also relates to a device oran apparatus for performing these operations. The systems and methodsdescribed herein can be specially constructed for the required purposes,such as the carrier network discussed above, or it may be a generalpurpose computer selectively activated or configured by a computerprogram stored in the computer. In particular, various general purposemachines may be used with computer programs written in accordance withthe teachings herein, or it may be more convenient to construct a morespecialized apparatus to perform the required operations.

The embodiments described herein can also be embodied as computerreadable code on a computer readable medium. The computer readablemedium is any data storage device that can store data, which canthereafter be read by a computer system. Examples of the computerreadable medium include hard drives, network attached storage (NAS),read-only memory, random-access memory, CD-ROMs, CD-Rs, CD-RWs, magnetictapes, and other optical and non-optical data storage devices. Thecomputer readable medium can also be distributed over a network coupledcomputer systems so that the computer readable code is stored andexecuted in a distributed fashion.

Although a few embodiments of the present invention have been describedin detail herein, it should be understood, by those of ordinary skill,that the present invention may be embodied in many other specific formswithout departing from the spirit or scope of the invention. Therefore,the present examples and embodiments are to be considered asillustrative and not restrictive, and the invention is not to be limitedto the details provided therein, but may be modified and practicedwithin the scope of the appended claims.

1. A system for intelligent web-based management of an electricalsystem, comprising: a data acquisition component communicativelyconnected to a sensor configured to acquire real-time data output fromthe electrical system; a web server communicatively connected to thedata acquisition component, the web server configured to transmit a userinterface to a client terminal, the web server comprising a virtualsystem model database communicatively connected to the data acquisitioncomponent, the virtual system model database configured to store avirtual system model of the electrical system, a power analyticsimulation engine comprising a virtual system modeling enginecommunicatively connected to the virtual system model database, thevirtual system modeling engine configured to generate a predicted dataoutput for the electrical system utilizing the virtual system model ofthe electrical system, and an analytics engine communicatively connectedto the virtual system model database, the analytics engine configured tomonitor the real-time data output and the predicted data output of theelectrical system, and to initiate a calibration and synchronizationoperation to update the virtual system model in real-time when adifference between the real-time data output and the predicted dataoutput exceeds a threshold; and a client terminal communicativelyconnected to the web server, the client terminal configured to displaythe user interface.
 2. A system as in claim 1, wherein the web serverfurther comprising a customer interface engine and a customer interfacedatabase.
 3. A system as in claim 2, wherein the customer interfaceengine comprises an e-commerce engine configured to manage a billingrecord, and wherein the customer interface database is communicativelyconnected to the customer interface engine, and the customer interfacedatabase comprises a billing database configured to store the billingrecord.
 4. A system as in claim 2, wherein the customer interface enginecomprises a customer management engine, the customer management engineconfigured to manage a customer record, and wherein the customerinterface database comprises a customer database communicativelyconnected to the customer management engine, the customer databaseconfigured to store the customer record.
 5. A system as in claim 4,wherein the customer record comprises a customer permission level.
 6. Asystem as in claim 1, the power analytic simulation engine furthercomprising: an equipment library engine configured to manage anequipment library record; and an equipment library databasecommunicatively connected to the equipment library engine, the equipmentlibrary database configured to store the equipment library record.
 7. Asystem as in claim 6, wherein the equipment library engine is configuredto allow a user to create or modify a user specific library ofequipment.
 8. A system as in claim 6, wherein the equipment libraryengine is configured to allow a user to create or modify a globallibrary of equipment.
 9. A system as in claim 1, the power analyticsimulation engine further comprising a real-time energy pricing engineconnected to a utility power pricing data table, the real-time energypricing engine configured to generate real-time utility power pricingdata.
 10. A system as in claim 1, the power analytic simulation enginefurther comprising a reporting engine configured to permit saving,printing, or exporting reports.
 11. A system as in claim 10, wherein thereports are in graphical format.
 12. A system as in claim 10, whereinthe reports are in a text format.
 13. A system as in claim 1, whereinthe web server is configured to use servlets to deliver content to theclient terminal.
 14. A method for interacting with an electrical systemmanagement application to perform power analytic simulations on avirtual system model of an electrical power system, comprising: ananalytics engine, monitoring real-time data from the electrical powersystem, monitoring predicted data for the electrical power system, thepredicted data generated using a virtual system model of the electricalpower system, and initiating a calibration and synchronization operationto update the virtual system model in real-time when a differencebetween the real-time data and the predicted data exceeds a threshold; aweb application server, receiving a user request to access theelectrical management system from a client terminal, and sending a userinterface for interaction with the electrical management system to theclient terminal, receiving user interaction data from the clientterminal, and communicating the user interaction data to the analyticsengine; and the analytics engine, performing a simulation using thevirtual system model based on the user interaction.
 15. A method as inclaim 14, further including: a virtual system model engine, accessing avirtual system model of the electrical power system stored in a virtualsystem model database, generating the, and communicating the generatedpredicted data to the web application server.
 16. A method as in claim14, wherein the user interface is provided in a graphical format.
 17. Amethod as in claim 14, wherein the web application server sends the userinterface to the client terminal through application servlets.